Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2015 | Oct. 22, 2015 | |
Entity Registrant Name | AMERICAN ELECTRIC POWER CO INC | |
Entity Central Index Key | 4,904 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2015 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q3 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 490,817,402 | |
Appalachian Power Co [Member] | ||
Entity Registrant Name | APPALACHIAN POWER CO | |
Entity Central Index Key | 6,879 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 13,499,500 | |
Indiana Michigan Power Co [Member] | ||
Entity Registrant Name | INDIANA MICHIGAN POWER CO | |
Entity Central Index Key | 50,172 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 1,400,000 | |
Ohio Power Co [Member] | ||
Entity Registrant Name | OHIO POWER CO | |
Entity Central Index Key | 73,986 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 27,952,473 | |
Public Service Co Of Oklahoma [Member] | ||
Entity Registrant Name | PUBLIC SERVICE CO OF OKLAHOMA | |
Entity Central Index Key | 81,027 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 9,013,000 | |
Southwestern Electric Power Co [Member] | ||
Entity Registrant Name | SOUTHWESTERN ELECTRIC POWER CO | |
Entity Central Index Key | 92,487 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 7,536,640 |
Consolidated Statements of Inco
Consolidated Statements of Income - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Revenues | ||||
Vertically Integrated Utilities | $ 2,436,000 | $ 2,432,000 | $ 7,082,000 | $ 7,217,000 |
Transmission and Distribution Utilities | 1,164,000 | 1,163,000 | 3,378,000 | 3,388,000 |
Generation & Marketing | 802,000 | 538,000 | 2,289,000 | 1,932,000 |
Other Revenues | 30,000 | 28,000 | 90,000 | 22,000 |
TOTAL REVENUES | 4,432,000 | 4,161,000 | 12,839,000 | 12,559,000 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 955,000 | 1,080,000 | 2,782,000 | 3,291,000 |
Purchased Electricity for Resale | 731,000 | 449,000 | 2,050,000 | 1,560,000 |
Other Operation | 691,000 | 685,000 | 1,955,000 | 1,985,000 |
Maintenance | 312,000 | 313,000 | 923,000 | 929,000 |
Depreciation and Amortization | 535,000 | 499,000 | 1,528,000 | 1,418,000 |
Taxes Other Than Income Taxes | 248,000 | 230,000 | 733,000 | 679,000 |
TOTAL EXPENSES | 3,472,000 | 3,256,000 | 9,971,000 | 9,862,000 |
OPERATING INCOME (LOSS) | 960,000 | 905,000 | 2,868,000 | 2,697,000 |
Other Income (Expense): | ||||
Interest and Investment Income | 2,000 | 1,000 | 6,000 | 5,000 |
Carrying Costs Income | 1,000 | 7,000 | 18,000 | 22,000 |
Allowance for Equity Funds Used During Construction | 33,000 | 27,000 | 97,000 | 74,000 |
Interest Expense | (221,000) | (217,000) | (659,000) | (650,000) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 775,000 | 723,000 | 2,330,000 | 2,148,000 |
Income Tax Expense (Credit) | 275,000 | 264,000 | 827,000 | 783,000 |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | 12,000 | 24,000 | 61,000 | 65,000 |
Income from Continuing Operations | 512,000 | 483,000 | 1,564,000 | 1,430,000 |
Income from Discontinued Operations, Net of Tax | 8,000 | 11,000 | 18,000 | 16,000 |
NET INCOME (LOSS) | 520,000 | 494,000 | 1,582,000 | 1,446,000 |
Net Income Attributable to Noncontrolling Interests | 1,000 | 1,000 | 4,000 | 3,000 |
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | $ 519,000 | $ 493,000 | $ 1,578,000 | $ 1,443,000 |
Earnings Per Share | ||||
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | 490,648,929 | 488,912,892 | 490,155,315 | 488,361,017 |
Income (Loss) from Continuing Operations, Per Basic Share | $ 1.04 | $ 0.99 | $ 3.18 | $ 2.92 |
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share | 0.02 | 0.02 | 0.04 | 0.03 |
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | $ 1.06 | $ 1.01 | $ 3.22 | $ 2.95 |
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | 490,800,335 | 488,970,647 | 490,411,020 | 488,597,178 |
Income (Loss) from Continuing Operations, Per Diluted Share | $ 1.04 | $ 0.99 | $ 3.18 | $ 2.92 |
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share | 0.02 | 0.02 | 0.04 | 0.03 |
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | 1.06 | 1.01 | 3.22 | 2.95 |
CASH DIVIDENDS DECLARED PER SHARE | $ 0.53 | $ 0.5 | $ 1.59 | $ 1.5 |
Appalachian Power Co [Member] | ||||
Revenues | ||||
Vertically Integrated Utilities | $ 685,312 | $ 672,459 | $ 2,184,943 | $ 2,202,967 |
Sales to AEP Affiliates | 39,389 | 35,455 | 115,740 | 108,439 |
Other Revenues | 2,857 | 1,970 | 7,870 | 6,537 |
TOTAL REVENUES | 727,558 | 709,884 | 2,308,553 | 2,317,943 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 188,576 | 194,303 | 595,308 | 627,943 |
Purchased Electricity for Resale | 80,452 | 85,656 | 258,836 | 340,680 |
Purchased Electricity from AEP Affiliates | 0 | 0 | 0 | 4,662 |
Other Operation | 101,841 | 103,835 | 311,631 | 297,269 |
Maintenance | 70,459 | 64,333 | 179,793 | 193,907 |
Depreciation and Amortization | 96,295 | 99,889 | 292,735 | 300,125 |
Taxes Other Than Income Taxes | 32,002 | 31,632 | 93,089 | 92,434 |
TOTAL EXPENSES | 569,625 | 579,648 | 1,731,392 | 1,857,020 |
OPERATING INCOME (LOSS) | 157,933 | 130,236 | 577,161 | 460,923 |
Other Income (Expense): | ||||
Interest Income | 290 | 521 | 1,128 | 1,311 |
Carrying Costs Income | 73 | 482 | 783 | (1,130) |
Allowance for Equity Funds Used During Construction | 3,432 | 1,665 | 10,337 | 4,525 |
Interest Expense | (46,625) | (52,738) | (145,600) | (157,540) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 115,103 | 80,166 | 443,809 | 308,089 |
Income Tax Expense (Credit) | 40,507 | 31,408 | 168,368 | 121,233 |
NET INCOME (LOSS) | 74,596 | 48,758 | 275,441 | 186,856 |
Indiana Michigan Power Co [Member] | ||||
Revenues | ||||
Vertically Integrated Utilities | 536,227 | 520,881 | 1,617,504 | 1,642,721 |
Sales to AEP Affiliates | 9,677 | 401 | 16,634 | 3,753 |
Other Revenues - Affiliated | 21,672 | 20,832 | 62,183 | 70,821 |
Other Revenues | 786 | 749 | 2,626 | 1,298 |
TOTAL REVENUES | 568,362 | 542,863 | 1,698,947 | 1,718,593 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 90,499 | 117,414 | 264,424 | 387,757 |
Purchased Electricity for Resale | 41,544 | 20,019 | 147,711 | 52,467 |
Purchased Electricity from AEP Affiliates | 67,281 | 66,561 | 182,239 | 203,807 |
Other Operation | 141,054 | 144,331 | 407,320 | 431,953 |
Maintenance | 53,727 | 59,043 | 160,907 | 161,854 |
Depreciation and Amortization | 49,215 | 50,585 | 150,162 | 150,062 |
Taxes Other Than Income Taxes | 21,608 | 22,059 | 66,992 | 64,685 |
TOTAL EXPENSES | 464,928 | 480,012 | 1,379,755 | 1,452,585 |
OPERATING INCOME (LOSS) | 103,434 | 62,851 | 319,192 | 266,008 |
Other Income (Expense): | ||||
Interest Income | 1,896 | 1,450 | 7,222 | 4,228 |
Allowance for Equity Funds Used During Construction | 2,157 | 5,596 | 9,107 | 14,364 |
Interest Expense | (23,144) | (22,617) | (68,889) | (71,955) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 84,343 | 47,280 | 266,632 | 212,645 |
Income Tax Expense (Credit) | 27,691 | 20,654 | 86,725 | 71,596 |
NET INCOME (LOSS) | 56,652 | 26,626 | 179,907 | 141,049 |
Ohio Power Co [Member] | ||||
Revenues | ||||
Transmission and Distribution Utilities | 775,905 | 793,900 | 2,320,372 | 2,380,768 |
Sales to AEP Affiliates | 4,426 | 43,733 | 79,690 | 120,154 |
Other Revenues | 1,953 | 1,564 | 6,416 | 4,628 |
TOTAL REVENUES | 782,284 | 839,197 | 2,406,478 | 2,505,550 |
Expenses | ||||
Purchased Electricity for Resale | 173,094 | 48,541 | 431,608 | 191,730 |
Purchased Electricity from AEP Affiliates | 45,834 | 315,903 | 462,645 | 897,658 |
Amortization of Generation Deferrals | 55,466 | 26,655 | 122,221 | 82,818 |
Other Operation | 170,144 | 145,163 | 446,817 | 428,074 |
Maintenance | 39,437 | 53,724 | 121,224 | 136,965 |
Depreciation and Amortization | 63,757 | 54,968 | 178,609 | 165,152 |
Taxes Other Than Income Taxes | 93,666 | 89,564 | 283,092 | 268,734 |
TOTAL EXPENSES | 641,398 | 734,518 | 2,046,216 | 2,171,131 |
OPERATING INCOME (LOSS) | 140,886 | 104,679 | 360,262 | 334,419 |
Other Income (Expense): | ||||
Interest Income | 1,165 | 1,986 | 4,328 | 8,159 |
Carrying Costs Income | (1,576) | 5,606 | 10,037 | 19,594 |
Allowance for Equity Funds Used During Construction | 2,228 | 1,825 | 7,015 | 4,893 |
Interest Expense | (32,593) | (31,171) | (96,313) | (96,937) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 110,110 | 82,925 | 285,329 | 270,128 |
Income Tax Expense (Credit) | 38,541 | 28,865 | 100,641 | 98,759 |
NET INCOME (LOSS) | 71,569 | 54,060 | 184,688 | 171,369 |
Public Service Co Of Oklahoma [Member] | ||||
Revenues | ||||
Vertically Integrated Utilities | 418,592 | 415,193 | 1,040,876 | 1,028,427 |
Sales to AEP Affiliates | 1,062 | 789 | 3,505 | 6,240 |
Other Revenues | 709 | 1,009 | 2,258 | 2,524 |
TOTAL REVENUES | 420,363 | 416,991 | 1,046,639 | 1,037,191 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 87,680 | 85,018 | 226,260 | 192,567 |
Purchased Electricity for Resale | 103,226 | 117,521 | 253,785 | 301,816 |
Purchased Electricity from AEP Affiliates | 0 | 0 | 0 | 11,024 |
Other Operation | 77,541 | 71,605 | 199,334 | 193,101 |
Maintenance | 27,239 | 21,800 | 74,322 | 76,223 |
Depreciation and Amortization | 30,832 | 24,496 | 90,148 | 73,085 |
Taxes Other Than Income Taxes | 9,327 | 9,137 | 27,843 | 27,757 |
TOTAL EXPENSES | 335,845 | 329,577 | 871,692 | 875,573 |
OPERATING INCOME (LOSS) | 84,518 | 87,414 | 174,947 | 161,618 |
Other Income (Expense): | ||||
Interest Income | 127 | 137 | 255 | 138 |
Allowance for Equity Funds Used During Construction | 2,342 | 194 | 5,952 | 2,215 |
Interest Expense | (14,950) | (13,913) | (44,372) | (41,009) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 72,037 | 73,832 | 136,782 | 122,962 |
Income Tax Expense (Credit) | 27,298 | 28,746 | 51,260 | 46,979 |
NET INCOME (LOSS) | 44,739 | 45,086 | 85,522 | 75,983 |
Southwestern Electric Power Co [Member] | ||||
Revenues | ||||
Vertically Integrated Utilities | 525,922 | 526,047 | 1,387,644 | 1,397,326 |
Sales to AEP Affiliates | 5,959 | 5,203 | 13,115 | 22,748 |
Other Revenues | 618 | 521 | 1,486 | 1,570 |
TOTAL REVENUES | 532,499 | 531,771 | 1,402,245 | 1,421,644 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 179,995 | 194,175 | 463,092 | 500,878 |
Purchased Electricity for Resale | 23,597 | 36,960 | 70,799 | 138,380 |
Purchased Electricity from AEP Affiliates | 0 | 0 | 0 | 3,766 |
Other Operation | 81,391 | 68,601 | 214,835 | 206,442 |
Maintenance | 34,425 | 29,867 | 100,076 | 93,946 |
Depreciation and Amortization | 48,862 | 46,791 | 143,780 | 138,316 |
Taxes Other Than Income Taxes | 23,014 | 22,246 | 66,062 | 63,272 |
TOTAL EXPENSES | 391,284 | 398,640 | 1,058,644 | 1,145,000 |
OPERATING INCOME (LOSS) | 141,215 | 133,131 | 343,601 | 276,644 |
Other Income (Expense): | ||||
Interest Income | 69 | 230 | 1,233 | 322 |
Allowance for Equity Funds Used During Construction | 7,053 | 3,137 | 18,164 | 7,415 |
Interest Expense | (29,263) | (31,644) | (91,423) | (95,258) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 119,074 | 104,854 | 271,575 | 189,123 |
Income Tax Expense (Credit) | 37,358 | 31,042 | 85,417 | 60,252 |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | 410 | 735 | 2,131 | 1,461 |
NET INCOME (LOSS) | 82,126 | 74,547 | 188,289 | 130,332 |
Net Income Attributable to Noncontrolling Interests | 1,013 | 1,109 | 3,002 | 3,337 |
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | $ 81,113 | $ 73,438 | $ 185,287 | $ 126,995 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Net Income (Loss) | $ 520,000 | $ 494,000 | $ 1,582,000 | $ 1,446,000 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | (6,000) | (2,000) | (11,000) | 6,000 |
Securities Available for Sale, Net of Tax | (1,000) | 0 | (1,000) | 1,000 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | 0 | 1,000 | 1,000 | 3,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | (7,000) | (1,000) | (11,000) | 10,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 513,000 | 493,000 | 1,571,000 | 1,456,000 |
Total Comprehensive Income Attributable to Noncontrolling Interest | 1,000 | 1,000 | 4,000 | 3,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | 512,000 | 492,000 | 1,567,000 | 1,453,000 |
Appalachian Power Co [Member] | ||||
Net Income (Loss) | 74,596 | 48,758 | 275,441 | 186,856 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | (222) | 170 | (91) | 582 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | (458) | (333) | (1,374) | (999) |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | (680) | (163) | (1,465) | (417) |
TOTAL COMPREHENSIVE INCOME (LOSS) | 73,916 | 48,595 | 273,976 | 186,439 |
Indiana Michigan Power Co [Member] | ||||
Net Income (Loss) | 56,652 | 26,626 | 179,907 | 141,049 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | 267 | 410 | 802 | 1,185 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | 11 | 42 | 33 | 128 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 278 | 452 | 835 | 1,313 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 56,930 | 27,078 | 180,742 | 142,362 |
Ohio Power Co [Member] | ||||
Net Income (Loss) | 71,569 | 54,060 | 184,688 | 171,369 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | (344) | (343) | (1,030) | (1,134) |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | (344) | (343) | (1,030) | (1,134) |
TOTAL COMPREHENSIVE INCOME (LOSS) | 71,225 | 53,717 | 183,658 | 170,235 |
Public Service Co Of Oklahoma [Member] | ||||
Net Income (Loss) | 44,739 | 45,086 | 85,522 | 75,983 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | (189) | (190) | (569) | (626) |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | (189) | (190) | (569) | (626) |
TOTAL COMPREHENSIVE INCOME (LOSS) | 44,550 | 44,896 | 84,953 | 75,357 |
Southwestern Electric Power Co [Member] | ||||
Net Income (Loss) | 82,126 | 74,547 | 188,289 | 130,332 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | 432 | 567 | 1,566 | 1,636 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | (240) | (235) | (719) | (704) |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 192 | 332 | 847 | 932 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 82,318 | 74,879 | 189,136 | 131,264 |
Total Comprehensive Income Attributable to Noncontrolling Interest | 1,013 | 1,109 | 3,002 | 3,337 |
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 81,305 | $ 73,770 | $ 186,134 | $ 127,927 |
Consolidated Statements of Com4
Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Cash Flow Hedges, Tax | $ (3,000) | $ (1,000) | $ (6,000) | $ 3,000 |
Securities Available for Sale, Tax | (1,000) | 0 | (1,000) | 0 |
Amortization of Pension and OPEB Deferred Costs, Tax | 0 | 1,000 | 0 | 2,000 |
Appalachian Power Co [Member] | ||||
Cash Flow Hedges, Tax | (120) | 92 | (49) | 314 |
Amortization of Pension and OPEB Deferred Costs, Tax | (247) | (179) | (740) | (538) |
Indiana Michigan Power Co [Member] | ||||
Cash Flow Hedges, Tax | 144 | 220 | 432 | 638 |
Amortization of Pension and OPEB Deferred Costs, Tax | 6 | 22 | 18 | 68 |
Ohio Power Co [Member] | ||||
Cash Flow Hedges, Tax | (185) | (185) | (555) | (611) |
Public Service Co Of Oklahoma [Member] | ||||
Cash Flow Hedges, Tax | (101) | (102) | (306) | (337) |
Southwestern Electric Power Co [Member] | ||||
Cash Flow Hedges, Tax | 232 | 305 | 843 | 881 |
Amortization of Pension and OPEB Deferred Costs, Tax | $ (129) | $ (126) | $ (387) | $ (379) |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Thousands | Total | Appalachian Power Co [Member] | Indiana Michigan Power Co [Member] | Ohio Power Co [Member] | Public Service Co Of Oklahoma [Member] | Southwestern Electric Power Co [Member] | Common Stock [Member] | Common Stock [Member]Appalachian Power Co [Member] | Common Stock [Member]Indiana Michigan Power Co [Member] | Common Stock [Member]Ohio Power Co [Member] | Common Stock [Member]Public Service Co Of Oklahoma [Member] | Common Stock [Member]Southwestern Electric Power Co [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member]Appalachian Power Co [Member] | Additional Paid-in Capital [Member]Indiana Michigan Power Co [Member] | Additional Paid-in Capital [Member]Ohio Power Co [Member] | Additional Paid-in Capital [Member]Public Service Co Of Oklahoma [Member] | Additional Paid-in Capital [Member]Southwestern Electric Power Co [Member] | Retained Earnings [Member] | Retained Earnings [Member]Appalachian Power Co [Member] | Retained Earnings [Member]Indiana Michigan Power Co [Member] | Retained Earnings [Member]Ohio Power Co [Member] | Retained Earnings [Member]Public Service Co Of Oklahoma [Member] | Retained Earnings [Member]Southwestern Electric Power Co [Member] | Accumulated Other Comprehensive Income [Member] | Accumulated Other Comprehensive Income [Member]Appalachian Power Co [Member] | Accumulated Other Comprehensive Income [Member]Indiana Michigan Power Co [Member] | Accumulated Other Comprehensive Income [Member]Ohio Power Co [Member] | Accumulated Other Comprehensive Income [Member]Public Service Co Of Oklahoma [Member] | Accumulated Other Comprehensive Income [Member]Southwestern Electric Power Co [Member] | Noncontrolling Interests [Member] | Noncontrolling Interests [Member]Southwestern Electric Power Co [Member] |
Beginning Balance at Dec. 31, 2013 | $ 16,086,000 | $ 3,229,432 | $ 1,922,153 | $ 1,625,265 | $ 942,101 | $ 2,055,917 | $ 3,303,000 | $ 260,458 | $ 56,584 | $ 321,201 | $ 157,230 | $ 135,660 | $ 6,131,000 | $ 1,809,562 | $ 980,896 | $ 663,782 | $ 364,037 | $ 674,606 | $ 6,766,000 | $ 1,156,461 | $ 900,182 | $ 633,203 | $ 415,076 | $ 1,253,617 | $ (115,000) | $ 2,951 | $ (15,509) | $ 7,079 | $ 5,758 | $ (8,444) | $ 1,000 | $ 478 |
Beginning Balance, Shares at Dec. 31, 2013 | 508,000,000 | |||||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||
Issuance of Common Stock, Value | 63,000 | $ 9,000 | 54,000 | |||||||||||||||||||||||||||||
Issuance of Common Stock, Shares | 2,000,000 | |||||||||||||||||||||||||||||||
Common Stock Dividends | (736,000) | (733,000) | (3,000) | |||||||||||||||||||||||||||||
Common Stock Dividends | (60,000) | (100,000) | (35,000) | (75,000) | (60,000) | (100,000) | (35,000) | (75,000) | ||||||||||||||||||||||||
Common Stock Dividends | (3,483) | (3,483) | ||||||||||||||||||||||||||||||
Other Changes in Equity | 3,000 | 6,000 | (6,000) | 3,000 | ||||||||||||||||||||||||||||
Net Income (Loss) | 1,443,000 | 126,995 | ||||||||||||||||||||||||||||||
Net Income (Loss) Attributable to Noncontrolling Interests | 3,000 | 3,337 | 3,000 | 3,337 | ||||||||||||||||||||||||||||
Net Income (Loss) | 1,446,000 | 186,856 | 141,049 | 171,369 | 75,983 | 130,332 | 186,856 | 141,049 | 171,369 | 75,983 | ||||||||||||||||||||||
Other Comprehensive Income (Loss) | 10,000 | (417) | 1,313 | (1,134) | (626) | 932 | 10,000 | (417) | 1,313 | (1,134) | (626) | 932 | ||||||||||||||||||||
Contribution of Mutual Energy SWEPCo, LLC from Parent | 0 | |||||||||||||||||||||||||||||||
Ending Balance at Sep. 30, 2014 | 16,872,000 | 3,355,871 | 1,964,515 | 1,760,500 | 1,017,458 | 2,108,698 | $ 3,312,000 | 260,458 | 56,584 | 321,201 | 157,230 | 135,660 | 6,191,000 | 1,809,562 | 980,896 | 663,782 | 364,037 | 674,606 | 7,470,000 | 1,283,317 | 941,231 | 769,572 | 491,059 | 1,305,612 | (105,000) | 2,534 | (14,196) | 5,945 | 5,132 | (7,512) | 4,000 | 332 |
Ending Balance, Shares at Sep. 30, 2014 | 510,000,000 | |||||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2014 | $ 16,824,000 | 3,366,928 | 1,953,949 | 1,980,210 | $ 1,028,215 | 2,097,201 | $ 3,313,000 | 260,458 | 56,584 | 321,201 | 157,230 | 135,660 | 6,204,000 | 1,809,562 | 980,896 | 838,782 | 364,037 | 674,606 | 7,406,000 | 1,291,876 | 930,829 | 814,625 | 502,005 | 1,293,986 | (103,000) | 5,032 | (14,360) | 5,602 | 4,943 | (7,466) | 4,000 | 415 |
Beginning Balance, Shares at Dec. 31, 2014 | 509,739,159 | 10,482,000 | 510,000,000 | |||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||
Issuance of Common Stock, Value | $ 68,000 | $ 9,000 | 59,000 | |||||||||||||||||||||||||||||
Issuance of Common Stock, Shares | 1,000,000 | |||||||||||||||||||||||||||||||
Common Stock Dividends | (783,000) | (780,000) | (3,000) | |||||||||||||||||||||||||||||
Common Stock Dividends | (181,250) | (90,000) | (156,250) | (90,000) | (181,250) | (90,000) | (156,250) | (90,000) | ||||||||||||||||||||||||
Common Stock Dividends | (3,099) | (3,099) | ||||||||||||||||||||||||||||||
Other Changes in Equity | 24,000 | 19,000 | 5,000 | |||||||||||||||||||||||||||||
Net Income (Loss) | 1,578,000 | 185,287 | ||||||||||||||||||||||||||||||
Net Income (Loss) Attributable to Noncontrolling Interests | 4,000 | 3,002 | 4,000 | 3,002 | ||||||||||||||||||||||||||||
Net Income (Loss) | 1,582,000 | 275,441 | 179,907 | 184,688 | $ 85,522 | 188,289 | 275,441 | 179,907 | 184,688 | 85,522 | ||||||||||||||||||||||
Other Comprehensive Income (Loss) | (11,000) | (1,465) | 835 | (1,030) | (569) | 847 | (11,000) | (1,465) | 835 | (1,030) | (569) | 847 | ||||||||||||||||||||
Contribution of Mutual Energy SWEPCo, LLC from Parent | 1,945 | 1,945 | ||||||||||||||||||||||||||||||
Ending Balance at Sep. 30, 2015 | $ 17,709,000 | $ 3,459,654 | $ 2,044,691 | $ 2,007,618 | $ 1,113,168 | $ 2,195,183 | $ 3,322,000 | $ 260,458 | $ 56,584 | $ 321,201 | $ 157,230 | $ 135,660 | $ 6,282,000 | $ 1,809,562 | $ 980,896 | $ 838,782 | $ 364,037 | $ 676,551 | $ 8,204,000 | $ 1,386,067 | $ 1,020,736 | $ 843,063 | $ 587,527 | $ 1,389,273 | (109,000) | $ 3,567 | $ (13,525) | $ 4,572 | $ 4,374 | $ (6,619) | $ 10,000 | $ 318 |
Ending Balance, Shares at Sep. 30, 2015 | 511,141,256 | 10,482,000 | 511,000,000 | |||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||
Pension and OPEB Adjustment Related to Mitchell Plant | $ 5,000 | $ 5,000 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 | |
Current Assets | |||
Cash and Cash Equivalents | $ 178,000 | $ 163,000 | |
Other Temporary Investments | 315,000 | 386,000 | |
Accounts Receivable: | |||
Customers | 662,000 | 637,000 | |
Accrued Unbilled Revenues | 147,000 | 146,000 | |
Pledged Accounts Receivable - AEP Credit | 987,000 | 987,000 | |
Miscellaneous | 84,000 | 85,000 | |
Allowance for Uncollectible Accounts | (27,000) | (20,000) | |
Total Accounts Receivable | 1,853,000 | 1,835,000 | |
Fuel | 376,000 | 581,000 | |
Materials and Supplies | 729,000 | 736,000 | |
Risk Management Assets | 143,000 | 178,000 | |
Regulatory Asset for Under-Recovered Fuel Costs | 105,000 | 127,000 | |
Margin Deposits | 85,000 | 95,000 | |
Assets Held for Sale | 608,000 | 103,000 | |
Prepayments and Other Current Assets | 156,000 | 274,000 | |
TOTAL CURRENT ASSETS | 4,548,000 | 4,478,000 | |
Property, Plant and Equipment | |||
Generation | 25,665,000 | 25,727,000 | |
Transmission | 13,305,000 | 12,433,000 | |
Distribution | 17,812,000 | 17,157,000 | |
Other Property, Plant and Equipment | 4,036,000 | 5,074,000 | |
Construction Work in Progress | 4,008,000 | 3,215,000 | |
Total Property, Plant and Equipment | 64,826,000 | 63,606,000 | |
Accumulated Depreciation and Amortization | 19,588,000 | 19,971,000 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 45,238,000 | 43,635,000 | |
Other Noncurrent Assets | |||
Regulatory Assets | 4,950,000 | 4,264,000 | |
Securitized Assets | 1,841,000 | 2,072,000 | |
Spent Nuclear Fuel and Decommissioning Trusts | 2,047,000 | 2,096,000 | |
Goodwill | 53,000 | 53,000 | |
Long-term Risk Management Assets | 353,000 | 294,000 | |
Assets Held for Sale | 0 | 522,000 | |
Deferred Charges and Other Noncurrent Assets | 2,069,000 | 2,219,000 | |
TOTAL OTHER NONCURRENT ASSETS | 11,313,000 | 11,520,000 | |
TOTAL ASSETS | 61,099,000 | 59,633,000 | |
Current Liabilities | |||
Accounts Payable | 1,274,000 | 1,258,000 | |
Short-term Debt: | |||
Securitized Debt for Receivables - AEP Credit | [1] | 750,000 | 744,000 |
Other Short-term Debt | 32,000 | 602,000 | |
Total Short-term Debt | 782,000 | 1,346,000 | |
Long-term Debt Due Within One Year | 1,826,000 | 2,500,000 | |
Long-term Debt Due Within One Year - Affiliated | 0 | 0 | |
Risk Management Liabilities | 75,000 | 92,000 | |
Customer Deposits | 335,000 | 324,000 | |
Accrued Taxes | 748,000 | 863,000 | |
Accrued Interest | 236,000 | 238,000 | |
Regulatory Liability for Over-Recovered Fuel Costs | 74,000 | 55,000 | |
Liabilities Held for Sale | 474,000 | 85,000 | |
Other Current Liabilities | 1,234,000 | 1,206,000 | |
TOTAL CURRENT LIABILITIES | 7,058,000 | 7,967,000 | |
Noncurrent Liabilities | |||
Long-term Debt | 17,600,000 | 16,101,000 | |
Long-term Risk Management Liabilities | 201,000 | 131,000 | |
Deferred Income Taxes | 11,425,000 | 10,892,000 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 3,762,000 | 3,892,000 | |
Asset Retirement Obligations | 1,944,000 | 1,951,000 | |
Employee Benefits and Pension Obligations | 535,000 | 630,000 | |
Liabilities Held for Sale | 0 | 350,000 | |
Deferred Credits and Other Noncurrent Liabilities | 865,000 | 895,000 | |
TOTAL NONCURRENT LIABILITIES | 36,332,000 | 34,842,000 | |
TOTAL LIABILITIES | $ 43,390,000 | $ 42,809,000 | |
Rate Matters | |||
Commitments and Contingencies | |||
Common Stock, Shares Authorized | 600,000,000 | 600,000,000 | |
Common Stock, Shares, Issued | 511,141,256 | 509,739,159 | |
Equity | |||
Common Stock | $ 3,322,000 | $ 3,313,000 | |
Paid-in Capital | 6,282,000 | 6,204,000 | |
Retained Earnings | 8,204,000 | 7,406,000 | |
Accumulated Other Comprehensive Income (Loss) | (109,000) | (103,000) | |
TOTAL COMMON SHAREHOLDER'S EQUITY | 17,699,000 | 16,820,000 | |
Noncontrolling Interests | 10,000 | 4,000 | |
TOTAL EQUITY | 17,709,000 | 16,824,000 | |
TOTAL LIABILITIES AND EQUITY | 61,099,000 | 59,633,000 | |
Appalachian Power Co [Member] | |||
Current Assets | |||
Cash and Cash Equivalents | 2,411 | 2,613 | |
Restricted Cash for Securitized Funding | 7,436 | 15,599 | |
Advances to Affiliates | 23,535 | 48,519 | |
Accounts Receivable: | |||
Customers | 118,331 | 114,711 | |
Affiliated Companies | 56,687 | 67,294 | |
Accrued Unbilled Revenues | 36,629 | 58,022 | |
Miscellaneous | 3,180 | 1,956 | |
Allowance for Uncollectible Accounts | (3,961) | (2,364) | |
Total Accounts Receivable | 210,866 | 239,619 | |
Fuel | 77,785 | 113,386 | |
Materials and Supplies | 126,941 | 131,285 | |
Risk Management Assets | 25,970 | 23,792 | |
Risk Management Assets - Affiliated | 1,380 | 0 | |
Deferred Income Tax Benefits | 0 | 23,955 | |
Regulatory Asset for Under-Recovered Fuel Costs | 69,013 | 66,076 | |
Prepayments and Other Current Assets | 27,673 | 13,660 | |
TOTAL CURRENT ASSETS | 573,010 | 678,504 | |
Property, Plant and Equipment | |||
Generation | 6,174,000 | 6,824,029 | |
Transmission | 2,271,351 | 2,228,029 | |
Distribution | 3,351,264 | 3,258,306 | |
Other Property, Plant and Equipment | 390,180 | 373,520 | |
Construction Work in Progress | 535,112 | 321,495 | |
Total Property, Plant and Equipment | 12,721,907 | 13,005,379 | |
Accumulated Depreciation and Amortization | 3,426,961 | 3,823,664 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 9,294,946 | 9,181,715 | |
Other Noncurrent Assets | |||
Regulatory Assets | 1,061,715 | 857,872 | |
Securitized Assets | 333,491 | 350,170 | |
Long-term Risk Management Assets | 2,035 | 4,891 | |
Deferred Charges and Other Noncurrent Assets | 141,012 | 159,230 | |
TOTAL OTHER NONCURRENT ASSETS | 1,538,253 | 1,372,163 | |
TOTAL ASSETS | 11,406,209 | 11,232,382 | |
Current Liabilities | |||
Advances from Affiliates | 35,224 | 0 | |
Accounts Payable | 186,317 | 166,821 | |
Affiliated Companies | 74,006 | 80,602 | |
Short-term Debt: | |||
Long-term Debt Due Within One Year | 318,020 | 552,212 | |
Long-term Debt Due Within One Year - Affiliated | 0 | 86,000 | |
Risk Management Liabilities | 6,902 | 11,017 | |
Customer Deposits | 79,237 | 71,766 | |
Accrued Taxes | 45,938 | 109,482 | |
Accrued Interest | 63,837 | 52,141 | |
Other Current Liabilities | 182,191 | 145,017 | |
TOTAL CURRENT LIABILITIES | 991,672 | 1,275,058 | |
Noncurrent Liabilities | |||
Long-term Debt | 3,637,275 | 3,342,062 | |
Long-term Risk Management Liabilities | 973 | 2,057 | |
Deferred Income Taxes | 2,410,754 | 2,288,842 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 646,262 | 652,867 | |
Asset Retirement Obligations | 110,474 | 122,300 | |
Employee Benefits and Pension Obligations | 119,986 | 127,980 | |
Deferred Credits and Other Noncurrent Liabilities | 29,159 | 54,288 | |
TOTAL NONCURRENT LIABILITIES | 6,954,883 | 6,590,396 | |
TOTAL LIABILITIES | $ 7,946,555 | $ 7,865,454 | |
Rate Matters | |||
Commitments and Contingencies | |||
Common Stock, Shares Authorized | 30,000,000 | 30,000,000 | |
Equity | |||
Common Stock | $ 260,458 | $ 260,458 | |
Paid-in Capital | 1,809,562 | 1,809,562 | |
Retained Earnings | 1,386,067 | 1,291,876 | |
Accumulated Other Comprehensive Income (Loss) | 3,567 | 5,032 | |
TOTAL EQUITY | 3,459,654 | 3,366,928 | |
TOTAL LIABILITIES AND EQUITY | 11,406,209 | 11,232,382 | |
Indiana Michigan Power Co [Member] | |||
Current Assets | |||
Cash and Cash Equivalents | 1,264 | 1,020 | |
Advances to Affiliates | 13,508 | 13,481 | |
Accounts Receivable: | |||
Customers | 58,950 | 56,978 | |
Affiliated Companies | 63,135 | 72,582 | |
Accrued Unbilled Revenues | 2,254 | 503 | |
Miscellaneous | 1,409 | 1,625 | |
Allowance for Uncollectible Accounts | (21) | (494) | |
Total Accounts Receivable | 125,727 | 131,194 | |
Fuel | 24,687 | 54,623 | |
Materials and Supplies | 189,764 | 201,089 | |
Risk Management Assets | 8,574 | 22,328 | |
Risk Management Assets - Affiliated | 2,053 | 0 | |
Accrued Tax Benefits | 6,232 | 24,788 | |
Prepayments and Other Current Assets | 27,549 | 27,968 | |
TOTAL CURRENT ASSETS | 399,358 | 476,491 | |
Property, Plant and Equipment | |||
Generation | 3,968,224 | 3,741,831 | |
Transmission | 1,380,689 | 1,358,419 | |
Distribution | 1,758,347 | 1,698,409 | |
Other Property, Plant and Equipment | 745,858 | 1,490,820 | |
Construction Work in Progress | 470,794 | 537,237 | |
Total Property, Plant and Equipment | 8,323,912 | 8,826,716 | |
Accumulated Depreciation and Amortization | 3,084,188 | 3,410,341 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 5,239,724 | 5,416,375 | |
Other Noncurrent Assets | |||
Regulatory Assets | 818,168 | 536,152 | |
Spent Nuclear Fuel and Decommissioning Trusts | 2,047,260 | 2,095,732 | |
Long-term Risk Management Assets | 1,338 | 3,317 | |
Deferred Charges and Other Noncurrent Assets | 123,676 | 137,209 | |
TOTAL OTHER NONCURRENT ASSETS | 2,990,442 | 2,772,410 | |
TOTAL ASSETS | 8,629,524 | 8,665,276 | |
Current Liabilities | |||
Advances from Affiliates | 151,004 | 142,501 | |
Accounts Payable | 132,292 | 168,294 | |
Affiliated Companies | 70,812 | 76,010 | |
Short-term Debt: | |||
Long-term Debt Due Within One Year | 301,148 | 382,187 | |
Risk Management Liabilities | 4,615 | 5,223 | |
Customer Deposits | 35,641 | 35,206 | |
Accrued Taxes | 58,791 | 72,742 | |
Accrued Interest | 13,263 | 26,677 | |
Obligations Under Capital Leases | 40,375 | 42,050 | |
Other Current Liabilities | 151,489 | 150,566 | |
TOTAL CURRENT LIABILITIES | 959,430 | 1,101,456 | |
Noncurrent Liabilities | |||
Long-term Debt | 1,759,503 | 1,645,210 | |
Long-term Risk Management Liabilities | 1,248 | 1,395 | |
Deferred Income Taxes | 1,329,163 | 1,264,167 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 1,041,910 | 1,199,694 | |
Asset Retirement Obligations | 1,379,004 | 1,337,179 | |
Deferred Credits and Other Noncurrent Liabilities | 114,575 | 162,226 | |
TOTAL NONCURRENT LIABILITIES | 5,625,403 | 5,609,871 | |
TOTAL LIABILITIES | $ 6,584,833 | $ 6,711,327 | |
Rate Matters | |||
Commitments and Contingencies | |||
Common Stock, Shares Authorized | 2,500,000 | 2,500,000 | |
Equity | |||
Common Stock | $ 56,584 | $ 56,584 | |
Paid-in Capital | 980,896 | 980,896 | |
Retained Earnings | 1,020,736 | 930,829 | |
Accumulated Other Comprehensive Income (Loss) | (13,525) | (14,360) | |
TOTAL EQUITY | 2,044,691 | 1,953,949 | |
TOTAL LIABILITIES AND EQUITY | 8,629,524 | 8,665,276 | |
Ohio Power Co [Member] | |||
Current Assets | |||
Cash and Cash Equivalents | 3,248 | 2,870 | |
Restricted Cash for Securitized Funding | 16,195 | 28,687 | |
Advances to Affiliates | 279,129 | 312,473 | |
Accounts Receivable: | |||
Customers | 35,711 | 57,906 | |
Affiliated Companies | 57,240 | 79,822 | |
Accrued Unbilled Revenues | 39,236 | 35,755 | |
Miscellaneous | 1,246 | 927 | |
Allowance for Uncollectible Accounts | (421) | (171) | |
Total Accounts Receivable | 133,012 | 174,239 | |
Notes Receivable Due Within One Year - Affiliated | 0 | 86,000 | |
Materials and Supplies | 75,878 | 60,909 | |
Risk Management Assets | 0 | 7,242 | |
Deferred Income Tax Benefits | 20,568 | 49,306 | |
Accrued Tax Benefits | 5,030 | 6,100 | |
Prepayments and Other Current Assets | 11,141 | 8,997 | |
TOTAL CURRENT ASSETS | 544,201 | 736,823 | |
Property, Plant and Equipment | |||
Transmission | 2,181,389 | 2,104,613 | |
Distribution | 4,231,051 | 4,087,601 | |
Other Property, Plant and Equipment | 446,485 | 390,848 | |
Construction Work in Progress | 212,093 | 218,667 | |
Total Property, Plant and Equipment | 7,071,018 | 6,801,729 | |
Accumulated Depreciation and Amortization | 2,086,931 | 2,038,120 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 4,984,087 | 4,763,609 | |
Other Noncurrent Assets | |||
Notes Receivable - Affiliated | 32,245 | 32,245 | |
Regulatory Assets | 1,150,864 | 1,318,939 | |
Securitized Assets | 91,899 | 109,999 | |
Long-term Risk Management Assets | 23,265 | 45,102 | |
Deferred Charges and Other Noncurrent Assets | 118,942 | 264,150 | |
TOTAL OTHER NONCURRENT ASSETS | 1,417,215 | 1,770,435 | |
TOTAL ASSETS | 6,945,503 | 7,270,867 | |
Current Liabilities | |||
Accounts Payable | 141,073 | 145,328 | |
Affiliated Companies | 88,324 | 172,741 | |
Short-term Debt: | |||
Long-term Debt Due Within One Year | 395,938 | 131,497 | |
Risk Management Liabilities | 2,823 | 1,943 | |
Customer Deposits | 60,235 | 53,922 | |
Accrued Taxes | 285,003 | 420,772 | |
Accrued Interest | 45,452 | 34,279 | |
Other Current Liabilities | 147,567 | 179,093 | |
TOTAL CURRENT LIABILITIES | 1,166,415 | 1,139,575 | |
Noncurrent Liabilities | |||
Long-term Debt | 1,770,112 | 2,165,626 | |
Long-term Risk Management Liabilities | 4,871 | 3,013 | |
Deferred Income Taxes | 1,402,369 | 1,405,620 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 535,458 | 514,691 | |
Employee Benefits and Pension Obligations | 29,978 | 36,662 | |
Deferred Credits and Other Noncurrent Liabilities | 28,682 | 25,470 | |
TOTAL NONCURRENT LIABILITIES | 3,771,470 | 4,151,082 | |
TOTAL LIABILITIES | $ 4,937,885 | $ 5,290,657 | |
Rate Matters | |||
Commitments and Contingencies | |||
Common Stock, Shares Authorized | 40,000,000 | 40,000,000 | |
Equity | |||
Common Stock | $ 321,201 | $ 321,201 | |
Paid-in Capital | 838,782 | 838,782 | |
Retained Earnings | 843,063 | 814,625 | |
Accumulated Other Comprehensive Income (Loss) | 4,572 | 5,602 | |
TOTAL EQUITY | 2,007,618 | 1,980,210 | |
TOTAL LIABILITIES AND EQUITY | 6,945,503 | 7,270,867 | |
Public Service Co Of Oklahoma [Member] | |||
Current Assets | |||
Cash and Cash Equivalents | 1,663 | 1,352 | |
Advances to Affiliates | 116,345 | 0 | |
Accounts Receivable: | |||
Customers | 24,770 | 28,448 | |
Affiliated Companies | 25,117 | 22,114 | |
Miscellaneous | 9,559 | 6,026 | |
Allowance for Uncollectible Accounts | (359) | (147) | |
Total Accounts Receivable | 59,087 | 56,441 | |
Fuel | 15,864 | 16,436 | |
Materials and Supplies | 52,519 | 50,880 | |
Risk Management Assets | 1,035 | 0 | |
Deferred Income Tax Benefits | 8,975 | 0 | |
Accrued Tax Benefits | 19,093 | 24,369 | |
Regulatory Asset for Under-Recovered Fuel Costs | 0 | 35,699 | |
Prepayments and Other Current Assets | 7,280 | 6,524 | |
TOTAL CURRENT ASSETS | 281,861 | 191,701 | |
Property, Plant and Equipment | |||
Generation | 1,296,921 | 1,264,724 | |
Transmission | 805,505 | 788,911 | |
Distribution | 2,185,778 | 2,080,221 | |
Other Property, Plant and Equipment | 435,807 | 421,568 | |
Construction Work in Progress | 274,470 | 204,753 | |
Total Property, Plant and Equipment | 4,998,481 | 4,760,177 | |
Accumulated Depreciation and Amortization | 1,383,116 | 1,319,554 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 3,615,365 | 3,440,623 | |
Other Noncurrent Assets | |||
Regulatory Assets | 180,605 | 154,327 | |
Employee Benefits and Pension Assets | 21,231 | 19,335 | |
Deferred Charges and Other Noncurrent Assets | 15,664 | 7,557 | |
TOTAL OTHER NONCURRENT ASSETS | 217,500 | 181,219 | |
TOTAL ASSETS | 4,114,726 | 3,813,543 | |
Current Liabilities | |||
Advances from Affiliates | 0 | 154,249 | |
Accounts Payable | 98,777 | 92,672 | |
Affiliated Companies | 37,267 | 51,744 | |
Short-term Debt: | |||
Long-term Debt Due Within One Year | 150,437 | 427 | |
Risk Management Liabilities | 70 | 918 | |
Customer Deposits | 50,147 | 48,700 | |
Accrued Taxes | 36,637 | 20,887 | |
Accrued Interest | 15,499 | 12,699 | |
Regulatory Liability for Over-Recovered Fuel Costs | 41,175 | 0 | |
Other Current Liabilities | 56,255 | 58,878 | |
TOTAL CURRENT LIABILITIES | 486,264 | 441,174 | |
Noncurrent Liabilities | |||
Long-term Debt | 1,140,536 | 1,040,609 | |
Long-term Risk Management Liabilities | 8 | 0 | |
Deferred Income Taxes | 958,168 | 898,352 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 339,161 | 334,479 | |
Asset Retirement Obligations | 42,680 | 37,030 | |
Employee Benefits and Pension Obligations | 16,456 | 20,095 | |
Deferred Credits and Other Noncurrent Liabilities | 18,285 | 13,589 | |
TOTAL NONCURRENT LIABILITIES | 2,515,294 | 2,344,154 | |
TOTAL LIABILITIES | $ 3,001,558 | $ 2,785,328 | |
Rate Matters | |||
Commitments and Contingencies | |||
Common Stock, Shares Authorized | 11,000,000 | 11,000,000 | |
Common Stock, Shares, Issued | 10,482,000 | 10,482,000 | |
Equity | |||
Common Stock | $ 157,230 | $ 157,230 | |
Paid-in Capital | 364,037 | 364,037 | |
Retained Earnings | 587,527 | 502,005 | |
Accumulated Other Comprehensive Income (Loss) | 4,374 | 4,943 | |
TOTAL EQUITY | 1,113,168 | 1,028,215 | |
TOTAL LIABILITIES AND EQUITY | 4,114,726 | 3,813,543 | |
Southwestern Electric Power Co [Member] | |||
Current Assets | |||
Cash and Cash Equivalents | 14,258 | 14,356 | |
Advances to Affiliates | 45,019 | 41,033 | |
Accounts Receivable: | |||
Customers | 41,086 | 46,738 | |
Affiliated Companies | 33,937 | 37,114 | |
Miscellaneous | 31,322 | 25,625 | |
Allowance for Uncollectible Accounts | (148) | (516) | |
Total Accounts Receivable | 106,197 | 108,961 | |
Fuel | 93,125 | 116,955 | |
Materials and Supplies | 72,735 | 73,666 | |
Risk Management Assets | 1,280 | 31 | |
Deferred Income Tax Benefits | 7,406 | 9,041 | |
Accrued Tax Benefits | 1,413 | 15,408 | |
Regulatory Asset for Under-Recovered Fuel Costs | 14,352 | 24,024 | |
Prepayments and Other Current Assets | 20,083 | 25,779 | |
TOTAL CURRENT ASSETS | 375,868 | 429,254 | |
Property, Plant and Equipment | |||
Generation | 3,928,939 | 3,864,543 | |
Transmission | 1,362,543 | 1,300,729 | |
Distribution | 1,945,074 | 1,894,572 | |
Other Property, Plant and Equipment | 895,958 | 878,753 | |
Construction Work in Progress | 681,991 | 471,980 | |
Total Property, Plant and Equipment | 8,814,505 | 8,410,577 | |
Accumulated Depreciation and Amortization | 2,611,129 | 2,503,290 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 6,203,376 | 5,907,287 | |
Other Noncurrent Assets | |||
Regulatory Assets | 413,434 | 393,602 | |
Employee Benefits and Pension Assets | 23,437 | 21,427 | |
Deferred Charges and Other Noncurrent Assets | 85,491 | 65,323 | |
TOTAL OTHER NONCURRENT ASSETS | 522,362 | 480,352 | |
TOTAL ASSETS | 7,101,606 | 6,816,893 | |
Current Liabilities | |||
Accounts Payable | 160,885 | 175,109 | |
Affiliated Companies | 58,866 | 67,410 | |
Short-term Debt: | |||
Long-term Debt Due Within One Year | 3,250 | 306,750 | |
Risk Management Liabilities | 1,302 | 1,082 | |
Customer Deposits | 60,594 | 59,903 | |
Accrued Taxes | 83,125 | 43,965 | |
Accrued Interest | 23,097 | 44,328 | |
Obligations Under Capital Leases | 22,081 | 17,557 | |
Other Current Liabilities | 81,965 | 104,553 | |
TOTAL CURRENT LIABILITIES | 495,165 | 820,657 | |
Noncurrent Liabilities | |||
Long-term Debt | 2,280,716 | 1,833,687 | |
Long-term Risk Management Liabilities | 757 | 0 | |
Deferred Income Taxes | 1,415,833 | 1,351,111 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 457,438 | 458,530 | |
Asset Retirement Obligations | 108,093 | 92,015 | |
Employee Benefits and Pension Obligations | 26,224 | 25,374 | |
Obligations Under Capital Leases | 74,533 | 91,044 | |
Deferred Credits and Other Noncurrent Liabilities | 47,664 | 47,274 | |
TOTAL NONCURRENT LIABILITIES | 4,411,258 | 3,899,035 | |
TOTAL LIABILITIES | $ 4,906,423 | $ 4,719,692 | |
Rate Matters | |||
Commitments and Contingencies | |||
Common Stock, Shares Authorized | 7,600,000 | 7,600,000 | |
Equity | |||
Common Stock | $ 135,660 | $ 135,660 | |
Paid-in Capital | 676,551 | 674,606 | |
Retained Earnings | 1,389,273 | 1,293,986 | |
Accumulated Other Comprehensive Income (Loss) | (6,619) | (7,466) | |
TOTAL COMMON SHAREHOLDER'S EQUITY | 2,194,865 | 2,096,786 | |
Noncontrolling Interests | 318 | 415 | |
TOTAL EQUITY | 2,195,183 | 2,097,201 | |
TOTAL LIABILITIES AND EQUITY | $ 7,101,606 | $ 6,816,893 | |
[1] | Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance |
Condensed Consolidated Balance7
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Current Assets | ||
Cash and Cash Equivalents | $ 178,000 | $ 163,000 |
Other Temporary Investments | 315,000 | 386,000 |
Fuel | 376,000 | 581,000 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 4,036,000 | 5,074,000 |
Accumulated Depreciation and Amortization | 19,588,000 | 19,971,000 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 1,826,000 | 2,500,000 |
Noncurrent Liabilities | ||
Long-term Debt | $ 17,600,000 | $ 16,101,000 |
Equity | ||
Common Stock, Par Value Per Share | $ 6.50 | $ 6.50 |
Common Stock, Shares Authorized | 600,000,000 | 600,000,000 |
Common Stock, Shares, Issued | 511,141,256 | 509,739,159 |
Treasury Stock, Shares | 20,336,592 | 20,336,592 |
Appalachian Power Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | $ 2,411 | $ 2,613 |
Fuel | 77,785 | 113,386 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 390,180 | 373,520 |
Accumulated Depreciation and Amortization | 3,426,961 | 3,823,664 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 318,020 | 552,212 |
Noncurrent Liabilities | ||
Long-term Debt | $ 3,637,275 | $ 3,342,062 |
Equity | ||
Common Stock, Shares Authorized | 30,000,000 | 30,000,000 |
Common Stock, Shares Outstanding | 13,499,500 | 13,499,500 |
Indiana Michigan Power Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | $ 1,264 | $ 1,020 |
Fuel | 24,687 | 54,623 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 745,858 | 1,490,820 |
Accumulated Depreciation and Amortization | 3,084,188 | 3,410,341 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 301,148 | 382,187 |
Noncurrent Liabilities | ||
Long-term Debt | $ 1,759,503 | $ 1,645,210 |
Equity | ||
Common Stock, No Par Value | ||
Common Stock, Shares Authorized | 2,500,000 | 2,500,000 |
Common Stock, Shares Outstanding | 1,400,000 | 1,400,000 |
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | ||
Current Liabilities | ||
Long-term Debt Due Within One Year | $ 97,953 | $ 85,657 |
Ohio Power Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | 3,248 | 2,870 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 446,485 | 390,848 |
Accumulated Depreciation and Amortization | 2,086,931 | 2,038,120 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 395,938 | 131,497 |
Noncurrent Liabilities | ||
Long-term Debt | $ 1,770,112 | $ 2,165,626 |
Equity | ||
Common Stock, No Par Value | ||
Common Stock, Shares Authorized | 40,000,000 | 40,000,000 |
Common Stock, Shares Outstanding | 27,952,473 | 27,952,473 |
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | ||
Current Liabilities | ||
Long-term Debt Due Within One Year | $ 45,864 | $ 45,427 |
Noncurrent Liabilities | ||
Long-term Debt | 141,177 | 187,041 |
Public Service Co Of Oklahoma [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | 1,663 | 1,352 |
Fuel | 15,864 | 16,436 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 435,807 | 421,568 |
Accumulated Depreciation and Amortization | 1,383,116 | 1,319,554 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 150,437 | 427 |
Noncurrent Liabilities | ||
Long-term Debt | $ 1,140,536 | $ 1,040,609 |
Equity | ||
Common Stock, Par Value Per Share | $ 15 | $ 15 |
Common Stock, Shares Authorized | 11,000,000 | 11,000,000 |
Common Stock, Shares, Issued | 10,482,000 | 10,482,000 |
Common Stock, Shares Outstanding | 9,013,000 | 9,013,000 |
Southwestern Electric Power Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | $ 14,258 | $ 14,356 |
Fuel | 93,125 | 116,955 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 895,958 | 878,753 |
Accumulated Depreciation and Amortization | 2,611,129 | 2,503,290 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 3,250 | 306,750 |
Noncurrent Liabilities | ||
Long-term Debt | $ 2,280,716 | $ 1,833,687 |
Equity | ||
Common Stock, Par Value Per Share | $ 18 | $ 18 |
Common Stock, Shares Authorized | 7,600,000 | 7,600,000 |
Common Stock, Shares Outstanding | 7,536,640 | 7,536,640 |
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | $ 11,693 | $ 12,695 |
Fuel | 27,194 | 38,920 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 291,896 | 288,183 |
Accumulated Depreciation and Amortization | 153,400 | 142,983 |
AEP Subsidiaries [Member] | ||
Current Assets | ||
Other Temporary Investments | 307,000 | 371,000 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 424,000 | 431,000 |
Noncurrent Liabilities | ||
Long-term Debt | $ 2,004,000 | $ 2,260,000 |
Condensed Consolidated Stateme8
Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Operating Activities | ||
Net Income (Loss) | $ 1,582,000 | $ 1,446,000 |
Income from Discontinued Operations | 18,000 | 16,000 |
Income from Continuing Operations | 1,564,000 | 1,430,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 1,528,000 | 1,418,000 |
Deferred Income Taxes | 529,000 | 385,000 |
Carrying Costs Income | (18,000) | (22,000) |
Allowance for Equity Funds Used During Construction | (97,000) | (74,000) |
Mark-to-Market of Risk Management Contracts | 18,000 | 15,000 |
Amortization of Nuclear Fuel | 102,000 | 114,000 |
Pension Contributions to Qualified Plan Trust | (92,000) | (70,000) |
Property Taxes | 247,000 | 220,000 |
Fuel Over/Under-Recovery, Net | 93,000 | (77,000) |
Deferral of Ohio Capacity Costs, Net | 35,000 | (106,000) |
Change in Other Noncurrent Assets | (106,000) | (41,000) |
Change in Other Noncurrent Liabilities | (1,000) | 271,000 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | (18,000) | (19,000) |
Fuel, Materials and Supplies | 194,000 | 222,000 |
Accounts Payable | (13,000) | (40,000) |
Accrued Taxes, Net | (68,000) | 20,000 |
Other Current Assets | 11,000 | 0 |
Other Current Liabilities | 2,000 | 69,000 |
Net Cash Flows from (Used for) Operating Activities | 3,910,000 | 3,715,000 |
Investing Activities | ||
Construction Expenditures | (3,283,000) | (2,897,000) |
Change in Other Temporary Investments, Net | 81,000 | 37,000 |
Purchases of Investment Securities | (1,489,000) | (791,000) |
Sales of Investment Securities | 1,437,000 | 746,000 |
Acquisitions of Nuclear Fuel | (53,000) | (109,000) |
Acquisitions of Assets/Businesses | (1,000) | (45,000) |
Other Investing Activities | 60,000 | (20,000) |
Net Cash Flows from (Used for) Investing Activities | (3,248,000) | (3,079,000) |
Financing Activities | ||
Issuance of Common Stock, Net | 68,000 | 63,000 |
Issuance of Long-term Debt | 2,931,000 | 1,206,000 |
Change in Short-term Debt, Net | (564,000) | 525,000 |
Retirement of Long-term Debt | (2,131,000) | (1,536,000) |
Make Whole Premium on Extinguishment of Long-term Debt | (93,000) | 0 |
Principal Payments for Capital Lease Obligations | (74,000) | (85,000) |
Dividends Paid on Common Stock | (783,000) | (736,000) |
Other Financing Activities | (1,000) | 3,000 |
Net Cash Flows from (Used for) Financing Activities | (647,000) | (560,000) |
Net Increase (Decrease) in Cash and Cash Equivalents | 15,000 | 76,000 |
Cash and Cash Equivalents at Beginning of Period | 163,000 | 118,000 |
Cash and Cash Equivalents at End of Period | 178,000 | 194,000 |
Cash Flows from Discontinued Operations | ||
Operating Activities | 10,000 | 10,000 |
Investing Activities | 2,000 | (2,000) |
Financing Activities | (12,000) | (8,000) |
Net Change in Cash and Cash Equivalents from Discontinued Operations | 0 | 0 |
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period | 0 | 0 |
Cash and Cash Equivalents from Discontinued Operations - End of Period | 0 | 0 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 639,000 | 649,000 |
Net Cash Paid (Received) for Income Taxes | 116,000 | 109,000 |
Noncash Acquisitions Under Capital Leases | 97,000 | 80,000 |
Construction Expenditures Included in Current Liabilities as of September 30, | 579,000 | 515,000 |
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | 31,000 | 0 |
Appalachian Power Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 275,441 | 186,856 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 292,735 | 300,125 |
Deferred Income Taxes | 179,143 | 114,778 |
Carrying Costs Income | (783) | 1,130 |
Allowance for Equity Funds Used During Construction | (10,337) | (4,525) |
Mark-to-Market of Risk Management Contracts | (5,902) | 255 |
Pension Contributions to Qualified Plan Trust | (9,981) | (8,963) |
Property Taxes | 27,980 | 25,856 |
Fuel Over/Under-Recovery, Net | (1,729) | (114,022) |
Change in Other Noncurrent Assets | (32,481) | (19,178) |
Change in Other Noncurrent Liabilities | (27,399) | 29,312 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 28,753 | 114,387 |
Fuel, Materials and Supplies | 31,352 | 78,977 |
Accounts Payable | 2,678 | (65,358) |
Accrued Taxes, Net | (75,290) | (43,092) |
Other Current Assets | (2,628) | (3,748) |
Other Current Liabilities | 15,411 | 9,085 |
Net Cash Flows from (Used for) Operating Activities | 686,963 | 601,875 |
Investing Activities | ||
Construction Expenditures | (456,721) | (342,291) |
Change in Advances to Affiliates, Net | 24,984 | 22,395 |
Other Investing Activities | 18,868 | (1,114) |
Net Cash Flows from (Used for) Investing Activities | (412,869) | (321,010) |
Financing Activities | ||
Issuance of Long-term Debt | 726,330 | 295,039 |
Change in Advances from Affiliates, Net | 35,224 | 0 |
Retirement of Long-term Debt | (672,552) | (512,702) |
Repayments of Related Party Debt | (86,000) | 0 |
Make Whole Premium on Extinguishment of Long-term Debt | (92,658) | 0 |
Principal Payments for Capital Lease Obligations | (3,843) | (4,255) |
Dividends Paid on Common Stock | (181,250) | (60,000) |
Other Financing Activities | 453 | 1,009 |
Net Cash Flows from (Used for) Financing Activities | (274,296) | (280,909) |
Net Increase (Decrease) in Cash and Cash Equivalents | (202) | (44) |
Cash and Cash Equivalents at Beginning of Period | 2,613 | 2,745 |
Cash and Cash Equivalents at End of Period | 2,411 | 2,701 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 128,435 | 136,919 |
Net Cash Paid (Received) for Income Taxes | 33,712 | 22,148 |
Noncash Acquisitions Under Capital Leases | 2,257 | 3,451 |
Construction Expenditures Included in Current Liabilities as of September 30, | 80,990 | 54,463 |
Indiana Michigan Power Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 179,907 | 141,049 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 150,162 | 150,062 |
Deferred Income Taxes | 38,338 | 15,792 |
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net | (148) | 23,951 |
Allowance for Equity Funds Used During Construction | (9,107) | (14,364) |
Mark-to-Market of Risk Management Contracts | 12,926 | (2,196) |
Amortization of Nuclear Fuel | 101,649 | 114,238 |
Fuel Over/Under-Recovery, Net | (16,055) | 18,931 |
Change in Other Noncurrent Assets | 27,286 | (36,596) |
Change in Other Noncurrent Liabilities | (6,330) | 66,502 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 5,467 | 59,646 |
Fuel, Materials and Supplies | 29,609 | 14,884 |
Accounts Payable | (14,001) | (12,052) |
Accrued Taxes, Net | 4,605 | 30,719 |
Other Current Assets | 6,923 | 11,741 |
Other Current Liabilities | (9,276) | (8,201) |
Net Cash Flows from (Used for) Operating Activities | 501,955 | 574,106 |
Investing Activities | ||
Construction Expenditures | (337,021) | (345,369) |
Change in Advances to Affiliates, Net | (27) | 42,364 |
Purchases of Investment Securities | (1,479,149) | (789,461) |
Sales of Investment Securities | 1,437,336 | 746,272 |
Acquisitions of Nuclear Fuel | (53,262) | (109,224) |
Other Investing Activities | 9,000 | 11,773 |
Net Cash Flows from (Used for) Investing Activities | (423,123) | (443,645) |
Financing Activities | ||
Issuance of Long-term Debt | 210,687 | 99,323 |
Change in Advances from Affiliates, Net | 8,503 | 95,899 |
Retirement of Long-term Debt | (178,471) | (190,550) |
Principal Payments for Capital Lease Obligations | (29,875) | (35,660) |
Dividends Paid on Common Stock | (90,000) | (100,000) |
Other Financing Activities | 568 | 628 |
Net Cash Flows from (Used for) Financing Activities | (78,588) | (130,360) |
Net Increase (Decrease) in Cash and Cash Equivalents | 244 | 101 |
Cash and Cash Equivalents at Beginning of Period | 1,020 | 1,317 |
Cash and Cash Equivalents at End of Period | 1,264 | 1,418 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 77,450 | 75,789 |
Net Cash Paid (Received) for Income Taxes | 17,203 | (1,475) |
Noncash Acquisitions Under Capital Leases | 1,990 | 5,015 |
Construction Expenditures Included in Current Liabilities as of September 30, | 51,582 | 69,241 |
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | 31,140 | 11 |
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage | 2,136 | 3,208 |
Ohio Power Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 184,688 | 171,369 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 178,609 | 165,152 |
Amortization Of Generation Deferrals | 122,221 | 82,818 |
Deferred Income Taxes | 28,099 | 27,990 |
Carrying Costs Income | (10,037) | (19,594) |
Allowance for Equity Funds Used During Construction | (7,015) | (4,893) |
Mark-to-Market of Risk Management Contracts | 31,818 | (5,003) |
Pension Contributions to Qualified Plan Trust | (7,671) | (6,547) |
Property Taxes | 148,407 | 148,124 |
Fuel Over/Under-Recovery, Net | (15,674) | 37,326 |
Deferral of Ohio Capacity Costs, Net | (30,662) | (138,737) |
Change in Other Noncurrent Assets | 29,168 | 35,962 |
Change in Other Noncurrent Liabilities | 30,913 | 59,081 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 41,227 | (20,395) |
Fuel, Materials and Supplies | (14,969) | (1,247) |
Accounts Payable | (78,831) | (83,029) |
Customer Deposits | 6,313 | 2,973 |
Accrued Taxes, Net | (134,699) | (173,470) |
Other Current Assets | (3,233) | (947) |
Other Current Liabilities | (4,707) | 26,039 |
Net Cash Flows from (Used for) Operating Activities | 493,965 | 302,972 |
Investing Activities | ||
Construction Expenditures | (346,831) | (327,972) |
Change in Restricted Cash for Securitized Funding | 12,492 | 1,653 |
Change in Advances to Affiliates, Net | 33,344 | 315,325 |
Proceeds from Notes Receivable Affiliated | 86,000 | 178,580 |
Other Investing Activities | 10,882 | 6,807 |
Net Cash Flows from (Used for) Investing Activities | (204,113) | 174,393 |
Financing Activities | ||
Retirement of Long-term Debt | (131,484) | (438,583) |
Principal Payments for Capital Lease Obligations | (2,937) | (3,912) |
Dividends Paid on Common Stock | (156,250) | (35,000) |
Other Financing Activities | 1,197 | 1,015 |
Net Cash Flows from (Used for) Financing Activities | (289,474) | (476,480) |
Net Increase (Decrease) in Cash and Cash Equivalents | 378 | 885 |
Cash and Cash Equivalents at Beginning of Period | 2,870 | 3,004 |
Cash and Cash Equivalents at End of Period | 3,248 | 3,889 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 79,019 | 90,188 |
Net Cash Paid (Received) for Income Taxes | 24,060 | 15,523 |
Noncash Acquisitions Under Capital Leases | 2,115 | 4,505 |
Construction Expenditures Included in Current Liabilities as of September 30, | 30,209 | 45,691 |
Public Service Co Of Oklahoma [Member] | ||
Operating Activities | ||
Net Income (Loss) | 85,522 | 75,983 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 90,148 | 73,085 |
Deferred Income Taxes | 40,052 | 27,327 |
Allowance for Equity Funds Used During Construction | (5,952) | (2,215) |
Mark-to-Market of Risk Management Contracts | (1,875) | 432 |
Pension Contributions to Qualified Plan Trust | (5,795) | (4,439) |
Property Taxes | (8,049) | (7,970) |
Fuel Over/Under-Recovery, Net | 76,874 | (33,246) |
Change in Other Noncurrent Assets | (13,066) | 2,035 |
Change in Other Noncurrent Liabilities | 7,733 | (2,015) |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | (2,646) | 333 |
Fuel, Materials and Supplies | (1,067) | 5,755 |
Accounts Payable | (9,339) | (28,643) |
Accrued Taxes, Net | 21,026 | 32,131 |
Other Current Assets | (1,866) | (4,034) |
Other Current Liabilities | 7,977 | 17,024 |
Net Cash Flows from (Used for) Operating Activities | 279,677 | 151,543 |
Investing Activities | ||
Construction Expenditures | (262,887) | (256,741) |
Change in Advances to Affiliates, Net | (116,345) | 0 |
Other Investing Activities | 7,679 | 2,881 |
Net Cash Flows from (Used for) Investing Activities | (371,553) | (253,860) |
Financing Activities | ||
Issuance of Long-term Debt | 248,785 | 74,973 |
Change in Advances from Affiliates, Net | (154,249) | 64,095 |
Retirement of Long-term Debt | (319) | (34,010) |
Principal Payments for Capital Lease Obligations | (2,765) | (2,785) |
Other Financing Activities | 735 | 595 |
Net Cash Flows from (Used for) Financing Activities | 92,187 | 102,868 |
Net Increase (Decrease) in Cash and Cash Equivalents | 311 | 551 |
Cash and Cash Equivalents at Beginning of Period | 1,352 | 1,277 |
Cash and Cash Equivalents at End of Period | 1,663 | 1,828 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 40,562 | 37,458 |
Net Cash Paid (Received) for Income Taxes | 12,772 | (416) |
Noncash Acquisitions Under Capital Leases | 1,546 | 2,098 |
Construction Expenditures Included in Current Liabilities as of September 30, | 37,328 | 33,527 |
Southwestern Electric Power Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 188,289 | 130,332 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 143,780 | 138,316 |
Deferred Income Taxes | 45,672 | 181,482 |
Allowance for Equity Funds Used During Construction | (18,164) | (7,415) |
Mark-to-Market of Risk Management Contracts | (272) | 802 |
Pension Contributions to Qualified Plan Trust | (8,052) | (3,832) |
Property Taxes | (13,024) | (12,503) |
Fuel Over/Under-Recovery, Net | 11,705 | (19,547) |
Change in Other Noncurrent Assets | 2,756 | 11,926 |
Change in Other Noncurrent Liabilities | (1,820) | 39 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 2,764 | 36,622 |
Fuel, Materials and Supplies | 24,761 | 22,500 |
Accounts Payable | (17,120) | (15,046) |
Accrued Taxes, Net | 53,155 | (76,982) |
Accrued Interest | (21,231) | (24,406) |
Other Current Assets | 2,794 | (7,448) |
Other Current Liabilities | (23,678) | (2,983) |
Net Cash Flows from (Used for) Operating Activities | 372,315 | 351,857 |
Investing Activities | ||
Construction Expenditures | (408,293) | (351,666) |
Change in Advances to Affiliates, Net | (2,038) | 0 |
Other Investing Activities | 4,427 | 4,334 |
Net Cash Flows from (Used for) Investing Activities | (405,904) | (347,332) |
Financing Activities | ||
Issuance of Long-term Debt | 445,949 | 99,633 |
Change in Advances from Affiliates, Net | 0 | (2,851) |
Retirement of Long-term Debt | (306,750) | (3,250) |
Principal Payments for Capital Lease Obligations | (13,398) | (13,673) |
Dividends Paid on Common Stock | (90,000) | (75,000) |
Dividends Paid on Common Stock | (3,099) | (3,483) |
Other Financing Activities | 789 | 844 |
Net Cash Flows from (Used for) Financing Activities | 33,491 | 2,220 |
Net Increase (Decrease) in Cash and Cash Equivalents | (98) | 6,745 |
Cash and Cash Equivalents at Beginning of Period | 14,356 | 17,241 |
Cash and Cash Equivalents at End of Period | 14,258 | 23,986 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 106,078 | 113,137 |
Net Cash Paid (Received) for Income Taxes | 12,320 | (13,820) |
Noncash Acquisitions Under Capital Leases | 1,493 | 3,923 |
Construction Expenditures Included in Current Liabilities as of September 30, | 85,268 | 88,291 |
Noncash Contribution of Mutual Energy SWEPCo, LLC from Parent | (1,945) | 0 |
Noncash Increase in Advances to Affiliates, Net due to Contribution of Mutual Energy SWEPCo, LLC | $ 1,948 | $ 0 |
Significant Accounting Matters
Significant Accounting Matters | 9 Months Ended |
Sep. 30, 2015 | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS General The unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2014 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 20, 2015 . Revenue Recognition Electricity Supply and Delivery Activities - Transactions with PJM Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. For regulated and nonregulated operations, we recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. APCo, I&M, KPCo and WPCo sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary’s retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenue on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement on January 1, 2014, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices. AEP’s nonregulated subsidiaries also purchase power from PJM and sell power to PJM. With the exception of certain dedicated load bilateral power supply contracts, these transactions are reported as gross purchases and sales. Earnings Per Share (EPS) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present our basic and diluted EPS calculations included on our condensed statements of income: Three Months Ended September 30, 2015 2014 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 512 $ 483 Less: Net Income Attributable to Noncontrolling Interests 1 1 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 511 $ 482 Weighted Average Number of Basic Shares Outstanding 490.6 $ 1.04 488.9 $ 0.99 Weighted Average Dilutive Effect of Restricted Stock Units 0.2 — 0.1 — Weighted Average Number of Diluted Shares Outstanding 490.8 $ 1.04 489.0 $ 0.99 Nine Months Ended September 30, 2015 2014 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 1,564 $ 1,430 Less: Net Income Attributable to Noncontrolling Interests 4 3 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,560 $ 1,427 Weighted Average Number of Basic Shares Outstanding 490.2 $ 3.18 488.4 $ 2.92 Weighted Average Dilutive Effect of Restricted Stock Units 0.2 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 490.4 $ 3.18 488.6 $ 2.92 There were no antidilutive shares outstanding as of September 30, 2015 and 2014 . Supplementary Cash Flow Information Nine Months Ended September 30, Cash Flow Information 2015 2014 (in millions) Cash Paid (Received) for: Cash Paid for Interest, Net of Capitalized Amounts $ 639 $ 649 Net Cash Paid for Income Taxes 116 109 Noncash Investing and Financing Activities: Noncash Acquisitions Under Capital Leases 97 80 Construction Expenditures Included in Current Liabilities as of September 30, 579 515 Construction Expenditures Included in Noncurrent Liabilities as of September 30, 66 — Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 31 — |
Appalachian Power Co [Member] | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 . |
Indiana Michigan Power Co [Member] | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 . |
Ohio Power Co [Member] | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 . |
Public Service Co Of Oklahoma [Member] | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 . |
Southwestern Electric Power Co [Member] | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 . |
New Accounting Pronouncements
New Accounting Pronouncements | 9 Months Ended |
Sep. 30, 2015 | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, we review the new accounting literature to determine its relevance, if any, to our business. The following final pronouncements will impact our financial statements. ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. We adopted ASU 2014-08 effective January 1, 2015. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. We plan to adopt ASU 2014-09 effective January 1, 2018. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. We plan to adopt ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. We include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. We intend to early adopt ASU 2015-03 for the 2015 Form 10-K. ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. We plan to adopt ASU 2015-05 effective January 1, 2016. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. We plan to adopt ASU 2015-11 effective January 1, 2017. ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13) In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. We have analyzed the impact of this new standard and determined that it will have no impact on the accounting of our contracts. Additionally, adoption has no impact on net income. We adopted ASU 2015-13 upon its issuance date. |
Appalachian Power Co [Member] | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following final pronouncements will impact the financial statements. ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K. ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017. ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13) In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it will have no impact on the accounting of the Registrant Subsidiaries' contracts. Additionally, adoption has no impact on net income. Management adopted ASU 2015-13 upon its issuance date. |
Indiana Michigan Power Co [Member] | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following final pronouncements will impact the financial statements. ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K. ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017. ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13) In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it will have no impact on the accounting of the Registrant Subsidiaries' contracts. Additionally, adoption has no impact on net income. Management adopted ASU 2015-13 upon its issuance date. |
Ohio Power Co [Member] | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following final pronouncements will impact the financial statements. ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K. ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017. ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13) In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it will have no impact on the accounting of the Registrant Subsidiaries' contracts. Additionally, adoption has no impact on net income. Management adopted ASU 2015-13 upon its issuance date. |
Public Service Co Of Oklahoma [Member] | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following final pronouncements will impact the financial statements. ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K. ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017. ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13) In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it will have no impact on the accounting of the Registrant Subsidiaries' contracts. Additionally, adoption has no impact on net income. Management adopted ASU 2015-13 upon its issuance date. |
Southwestern Electric Power Co [Member] | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following final pronouncements will impact the financial statements. ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for annual periods beginning after December 15, 2016. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 simplifying the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K. ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 providing guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 simplifying the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first-out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017. ASU 2015-13 “Application of the Normal Purchases and Normal Sales Scope Exception to Certain Electricity Contracts within Nodal Energy Markets” (ASU 2015-13) In August 2015, the FASB issued ASU 2015-13 clarifying whether a contract for the purchase or sale of electricity on a forward basis should be eligible to meet the physical delivery criterion of the normal purchases and normal sales scope exception when either the delivery location is within a nodal energy market or the contract necessitates transmission through a nodal energy market and one of the contracting parties incurs charges (or credits) for the transmission of electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. Under the new standard, the use of locational marginal pricing by an independent system operator does not cause a contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. As a result, an entity may elect to designate that contract as a normal purchase or normal sale. The new accounting guidance is effective upon issuance and applied prospectively. Management has analyzed the impact of this new standard and determined that it will have no impact on the accounting of the Registrant Subsidiaries' contracts. Additionally, adoption has no impact on net income. Management adopted ASU 2015-13 upon its issuance date. |
Comprehensive Income
Comprehensive Income | 9 Months Ended |
Sep. 30, 2015 | |
Comprehensive Income | COMPREHENSIVE INCOME Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2015 and 2014 . All amounts in the following tables are presented net of related income taxes. Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (5 ) $ (18 ) $ 8 $ (87 ) $ (102 ) Change in Fair Value Recognized in AOCI (3 ) — (1 ) — (4 ) Amounts Reclassified from AOCI (3 ) — — — (3 ) Net Current Period Other Comprehensive Loss (6 ) — (1 ) — (7 ) Balance in AOCI as of September 30, 2015 $ (11 ) $ (18 ) $ 7 $ (87 ) $ (109 ) Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2014 $ 6 $ (21 ) $ 8 $ (97 ) $ (104 ) Change in Fair Value Recognized in AOCI 3 — — — 3 Amounts Reclassified from AOCI (6 ) 1 — 1 (4 ) Net Current Period Other Comprehensive Income (Loss) (3 ) 1 — 1 (1 ) Balance in AOCI as of September 30, 2014 $ 3 $ (20 ) $ 8 $ (96 ) $ (105 ) Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 1 $ (19 ) $ 8 $ (93 ) $ (103 ) Change in Fair Value Recognized in AOCI (2 ) — (1 ) — (3 ) Amounts Reclassified from AOCI (10 ) 1 — 1 (8 ) Net Current Period Other Comprehensive Income (Loss) (12 ) 1 (1 ) 1 (11 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — 5 5 Balance in AOCI as of September 30, 2015 $ (11 ) $ (18 ) $ 7 $ (87 ) $ (109 ) Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (23 ) $ 7 $ (99 ) $ (115 ) Change in Fair Value Recognized in AOCI (8 ) — 1 — (7 ) Amounts Reclassified from AOCI 11 3 — 3 17 Net Current Period Other Comprehensive Income 3 3 1 3 10 Balance in AOCI as of September 30, 2014 $ 3 $ (20 ) $ 8 $ (96 ) $ (105 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Generation & Marketing Revenues $ (19 ) $ — Purchased Electricity for Resale 14 (9 ) Subtotal – Commodity (5 ) (9 ) Interest Rate and Foreign Currency: Interest Expense — 2 Subtotal – Interest Rate and Foreign Currency — 2 Reclassifications from AOCI, before Income Tax (Expense) Credit (5 ) (7 ) Income Tax (Expense) Credit (2 ) (2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (3 ) (5 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (5 ) (5 ) Amortization of Actuarial (Gains)/Losses 5 7 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2 Income Tax (Expense) Credit — 1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (3 ) $ (4 ) Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Generation & Marketing Revenues $ (36 ) $ — Purchased Electricity for Resale 20 20 Regulatory Assets/(Liabilities), Net (a) — (3 ) Subtotal – Commodity (16 ) 17 Interest Rate and Foreign Currency: Interest Expense 1 6 Subtotal – Interest Rate and Foreign Currency 1 6 Reclassifications from AOCI, before Income Tax (Expense) Credit (15 ) 23 Income Tax (Expense) Credit (6 ) 9 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (9 ) 14 Pension and OPEB Amortization of Prior Service Cost (Credit) (15 ) (15 ) Amortization of Actuarial (Gains)/Losses 16 21 Reclassifications from AOCI, before Income Tax (Expense) Credit 1 6 Income Tax (Expense) Credit — 3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1 3 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (8 ) $ 17 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Appalachian Power Co [Member] | |
Comprehensive Income | COMPREHENSIVE INCOME Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2015 and 2014 . All amounts in the following tables are presented net of related income taxes. APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — (222 ) (458 ) (680 ) Net Current Period Other Comprehensive Loss — (222 ) (458 ) (680 ) Balance in AOCI as of September 30, 2015 $ — $ 3,805 $ (238 ) $ 3,567 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 170 (333 ) (163 ) Net Current Period Other Comprehensive Income (Loss) — 170 (333 ) (163 ) Balance in AOCI as of September 30, 2014 $ — $ 3,766 $ (1,232 ) $ 2,534 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 3,896 $ 1,136 $ 5,032 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — (91 ) (1,374 ) (1,465 ) Net Current Period Other Comprehensive Loss — (91 ) (1,374 ) (1,465 ) Balance in AOCI as of September 30, 2015 $ — $ 3,805 $ (238 ) $ 3,567 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 94 $ 3,090 $ (233 ) $ 2,951 Change in Fair Value Recognized in AOCI 1,686 — — 1,686 Amounts Reclassified from AOCI (1,780 ) 676 (999 ) (2,103 ) Net Current Period Other Comprehensive Income (Loss) (94 ) 676 (999 ) (417 ) Balance in AOCI as of September 30, 2014 $ — $ 3,766 $ (1,232 ) $ 2,534 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 267 11 278 Net Current Period Other Comprehensive Income — 267 11 278 Balance in AOCI as of September 30, 2015 $ — $ (13,604 ) $ 79 $ (13,525 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 410 42 452 Net Current Period Other Comprehensive Income — 410 42 452 Balance in AOCI as of September 30, 2014 $ — $ (14,745 ) $ 549 $ (14,196 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (14,406 ) $ 46 $ (14,360 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 802 33 835 Net Current Period Other Comprehensive Income — 802 33 835 Balance in AOCI as of September 30, 2015 $ — $ (13,604 ) $ 79 $ (13,525 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 46 $ (15,976 ) $ 421 $ (15,509 ) Change in Fair Value Recognized in AOCI 1,130 — — 1,130 Amounts Reclassified from AOCI (1,176 ) 1,231 128 183 Net Current Period Other Comprehensive Income (Loss) (46 ) 1,231 128 1,313 Balance in AOCI as of September 30, 2014 $ — $ (14,745 ) $ 549 $ (14,196 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (344 ) (344 ) Net Current Period Other Comprehensive Loss — (344 ) (344 ) Balance in AOCI as of September 30, 2015 $ — $ 4,572 $ 4,572 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of September 30, 2014 $ — $ 5,945 $ 5,945 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 5,602 $ 5,602 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (1,030 ) (1,030 ) Net Current Period Other Comprehensive Loss — (1,030 ) (1,030 ) Balance in AOCI as of September 30, 2015 $ — $ 4,572 $ 4,572 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2013 $ 105 $ 6,974 $ 7,079 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (105 ) (1,029 ) (1,134 ) Net Current Period Other Comprehensive Loss (105 ) (1,029 ) (1,134 ) Balance in AOCI as of September 30, 2014 $ — $ 5,945 $ 5,945 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (189 ) (189 ) Net Current Period Other Comprehensive Loss — (189 ) (189 ) Balance in AOCI as of September 30, 2015 $ — $ 4,374 $ 4,374 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of September 30, 2014 $ — $ 5,132 $ 5,132 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 4,943 $ 4,943 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (569 ) (569 ) Net Current Period Other Comprehensive Loss — (569 ) (569 ) Balance in AOCI as of September 30, 2015 $ — $ 4,374 $ 4,374 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2013 $ 57 $ 5,701 $ 5,758 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (57 ) (569 ) (626 ) Net Current Period Other Comprehensive Loss (57 ) (569 ) (626 ) Balance in AOCI as of September 30, 2014 $ — $ 5,132 $ 5,132 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 432 (240 ) 192 Net Current Period Other Comprehensive Income (Loss) — 432 (240 ) 192 Balance in AOCI as of September 30, 2015 $ — $ (9,470 ) $ 2,851 $ (6,619 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (235 ) 332 Net Current Period Other Comprehensive Income (Loss) — 567 (235 ) 332 Balance in AOCI as of September 30, 2014 $ — $ (11,602 ) $ 4,090 $ (7,512 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (11,036 ) $ 3,570 $ (7,466 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 1,566 (719 ) 847 Net Current Period Other Comprehensive Income (Loss) — 1,566 (719 ) 847 Balance in AOCI as of September 30, 2015 $ — $ (9,470 ) $ 2,851 $ (6,619 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 66 $ (13,304 ) $ 4,794 $ (8,444 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI (66 ) 1,702 (704 ) 932 Net Current Period Other Comprehensive Income (Loss) (66 ) 1,702 (704 ) 932 Balance in AOCI as of September 30, 2014 $ — $ (11,602 ) $ 4,090 $ (7,512 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (342 ) 262 Subtotal – Interest Rate and Foreign Currency (342 ) 262 Reclassifications from AOCI, before Income Tax (Expense) Credit (342 ) 262 Income Tax (Expense) Credit (120 ) 92 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (222 ) 170 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,282 ) (1,281 ) Amortization of Actuarial (Gains)/Losses 577 769 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (512 ) Income Tax (Expense) Credit (247 ) (179 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (680 ) $ (163 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense (140 ) 1,042 Subtotal – Interest Rate and Foreign Currency (140 ) 1,042 Reclassifications from AOCI, before Income Tax (Expense) Credit (140 ) (1,696 ) Income Tax (Expense) Credit (49 ) (592 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (91 ) (1,104 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (3,847 ) (3,846 ) Amortization of Actuarial (Gains)/Losses 1,733 2,309 Reclassifications from AOCI, before Income Tax (Expense) Credit (2,114 ) (1,537 ) Income Tax (Expense) Credit (740 ) (538 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1,374 ) (999 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,465 ) $ (2,103 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 412 631 Subtotal – Interest Rate and Foreign Currency 412 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 412 631 Income Tax (Expense) Credit 145 221 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 267 410 Pension and OPEB Amortization of Prior Service Cost (Credit) (198 ) (200 ) Amortization of Actuarial (Gains)/Losses 215 264 Reclassifications from AOCI, before Income Tax (Expense) Credit 17 64 Income Tax (Expense) Credit 6 22 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11 42 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 452 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 1,234 1,893 Subtotal – Interest Rate and Foreign Currency 1,234 1,893 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,234 84 Income Tax (Expense) Credit 432 29 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 802 55 Pension and OPEB Amortization of Prior Service Cost (Credit) (596 ) (597 ) Amortization of Actuarial (Gains)/Losses 647 791 Reclassifications from AOCI, before Income Tax (Expense) Credit 51 194 Income Tax (Expense) Credit 18 66 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 33 128 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 835 $ 183 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (4 ) (3 ) Interest Expense (526 ) (524 ) Subtotal – Interest Rate and Foreign Currency (530 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (530 ) (527 ) Income Tax (Expense) Credit (186 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (344 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (10 ) (9 ) Interest Expense (1,574 ) (1,572 ) Subtotal – Interest Rate and Foreign Currency (1,584 ) (1,581 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,584 ) (1,743 ) Income Tax (Expense) Credit (554 ) (609 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,030 ) $ (1,134 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (291 ) (292 ) Subtotal – Interest Rate and Foreign Currency (291 ) (292 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (291 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (189 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (875 ) (876 ) Subtotal – Interest Rate and Foreign Currency (875 ) (876 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (875 ) (964 ) Income Tax (Expense) Credit (306 ) (338 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (569 ) $ (626 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 665 872 Subtotal – Interest Rate and Foreign Currency 665 872 Reclassifications from AOCI, before Income Tax (Expense) Credit 665 872 Income Tax (Expense) Credit 233 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 432 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (468 ) (478 ) Amortization of Actuarial (Gains)/Losses 99 118 Reclassifications from AOCI, before Income Tax (Expense) Credit (369 ) (360 ) Income Tax (Expense) Credit (129 ) (125 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (240 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 192 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 2,409 2,616 Subtotal – Interest Rate and Foreign Currency 2,409 2,616 Reclassifications from AOCI, before Income Tax (Expense) Credit 2,409 2,515 Income Tax (Expense) Credit 843 879 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,566 1,636 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,402 ) (1,433 ) Amortization of Actuarial (Gains)/Losses 296 351 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,106 ) (1,082 ) Income Tax (Expense) Credit (387 ) (378 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (719 ) (704 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 847 $ 932 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Indiana Michigan Power Co [Member] | |
Comprehensive Income | COMPREHENSIVE INCOME Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2015 and 2014 . All amounts in the following tables are presented net of related income taxes. APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — (222 ) (458 ) (680 ) Net Current Period Other Comprehensive Loss — (222 ) (458 ) (680 ) Balance in AOCI as of September 30, 2015 $ — $ 3,805 $ (238 ) $ 3,567 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 170 (333 ) (163 ) Net Current Period Other Comprehensive Income (Loss) — 170 (333 ) (163 ) Balance in AOCI as of September 30, 2014 $ — $ 3,766 $ (1,232 ) $ 2,534 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 3,896 $ 1,136 $ 5,032 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — (91 ) (1,374 ) (1,465 ) Net Current Period Other Comprehensive Loss — (91 ) (1,374 ) (1,465 ) Balance in AOCI as of September 30, 2015 $ — $ 3,805 $ (238 ) $ 3,567 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 94 $ 3,090 $ (233 ) $ 2,951 Change in Fair Value Recognized in AOCI 1,686 — — 1,686 Amounts Reclassified from AOCI (1,780 ) 676 (999 ) (2,103 ) Net Current Period Other Comprehensive Income (Loss) (94 ) 676 (999 ) (417 ) Balance in AOCI as of September 30, 2014 $ — $ 3,766 $ (1,232 ) $ 2,534 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 267 11 278 Net Current Period Other Comprehensive Income — 267 11 278 Balance in AOCI as of September 30, 2015 $ — $ (13,604 ) $ 79 $ (13,525 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 410 42 452 Net Current Period Other Comprehensive Income — 410 42 452 Balance in AOCI as of September 30, 2014 $ — $ (14,745 ) $ 549 $ (14,196 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (14,406 ) $ 46 $ (14,360 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 802 33 835 Net Current Period Other Comprehensive Income — 802 33 835 Balance in AOCI as of September 30, 2015 $ — $ (13,604 ) $ 79 $ (13,525 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 46 $ (15,976 ) $ 421 $ (15,509 ) Change in Fair Value Recognized in AOCI 1,130 — — 1,130 Amounts Reclassified from AOCI (1,176 ) 1,231 128 183 Net Current Period Other Comprehensive Income (Loss) (46 ) 1,231 128 1,313 Balance in AOCI as of September 30, 2014 $ — $ (14,745 ) $ 549 $ (14,196 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (344 ) (344 ) Net Current Period Other Comprehensive Loss — (344 ) (344 ) Balance in AOCI as of September 30, 2015 $ — $ 4,572 $ 4,572 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of September 30, 2014 $ — $ 5,945 $ 5,945 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 5,602 $ 5,602 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (1,030 ) (1,030 ) Net Current Period Other Comprehensive Loss — (1,030 ) (1,030 ) Balance in AOCI as of September 30, 2015 $ — $ 4,572 $ 4,572 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2013 $ 105 $ 6,974 $ 7,079 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (105 ) (1,029 ) (1,134 ) Net Current Period Other Comprehensive Loss (105 ) (1,029 ) (1,134 ) Balance in AOCI as of September 30, 2014 $ — $ 5,945 $ 5,945 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (189 ) (189 ) Net Current Period Other Comprehensive Loss — (189 ) (189 ) Balance in AOCI as of September 30, 2015 $ — $ 4,374 $ 4,374 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of September 30, 2014 $ — $ 5,132 $ 5,132 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 4,943 $ 4,943 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (569 ) (569 ) Net Current Period Other Comprehensive Loss — (569 ) (569 ) Balance in AOCI as of September 30, 2015 $ — $ 4,374 $ 4,374 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2013 $ 57 $ 5,701 $ 5,758 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (57 ) (569 ) (626 ) Net Current Period Other Comprehensive Loss (57 ) (569 ) (626 ) Balance in AOCI as of September 30, 2014 $ — $ 5,132 $ 5,132 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 432 (240 ) 192 Net Current Period Other Comprehensive Income (Loss) — 432 (240 ) 192 Balance in AOCI as of September 30, 2015 $ — $ (9,470 ) $ 2,851 $ (6,619 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (235 ) 332 Net Current Period Other Comprehensive Income (Loss) — 567 (235 ) 332 Balance in AOCI as of September 30, 2014 $ — $ (11,602 ) $ 4,090 $ (7,512 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (11,036 ) $ 3,570 $ (7,466 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 1,566 (719 ) 847 Net Current Period Other Comprehensive Income (Loss) — 1,566 (719 ) 847 Balance in AOCI as of September 30, 2015 $ — $ (9,470 ) $ 2,851 $ (6,619 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 66 $ (13,304 ) $ 4,794 $ (8,444 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI (66 ) 1,702 (704 ) 932 Net Current Period Other Comprehensive Income (Loss) (66 ) 1,702 (704 ) 932 Balance in AOCI as of September 30, 2014 $ — $ (11,602 ) $ 4,090 $ (7,512 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (342 ) 262 Subtotal – Interest Rate and Foreign Currency (342 ) 262 Reclassifications from AOCI, before Income Tax (Expense) Credit (342 ) 262 Income Tax (Expense) Credit (120 ) 92 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (222 ) 170 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,282 ) (1,281 ) Amortization of Actuarial (Gains)/Losses 577 769 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (512 ) Income Tax (Expense) Credit (247 ) (179 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (680 ) $ (163 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense (140 ) 1,042 Subtotal – Interest Rate and Foreign Currency (140 ) 1,042 Reclassifications from AOCI, before Income Tax (Expense) Credit (140 ) (1,696 ) Income Tax (Expense) Credit (49 ) (592 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (91 ) (1,104 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (3,847 ) (3,846 ) Amortization of Actuarial (Gains)/Losses 1,733 2,309 Reclassifications from AOCI, before Income Tax (Expense) Credit (2,114 ) (1,537 ) Income Tax (Expense) Credit (740 ) (538 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1,374 ) (999 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,465 ) $ (2,103 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 412 631 Subtotal – Interest Rate and Foreign Currency 412 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 412 631 Income Tax (Expense) Credit 145 221 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 267 410 Pension and OPEB Amortization of Prior Service Cost (Credit) (198 ) (200 ) Amortization of Actuarial (Gains)/Losses 215 264 Reclassifications from AOCI, before Income Tax (Expense) Credit 17 64 Income Tax (Expense) Credit 6 22 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11 42 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 452 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 1,234 1,893 Subtotal – Interest Rate and Foreign Currency 1,234 1,893 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,234 84 Income Tax (Expense) Credit 432 29 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 802 55 Pension and OPEB Amortization of Prior Service Cost (Credit) (596 ) (597 ) Amortization of Actuarial (Gains)/Losses 647 791 Reclassifications from AOCI, before Income Tax (Expense) Credit 51 194 Income Tax (Expense) Credit 18 66 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 33 128 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 835 $ 183 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (4 ) (3 ) Interest Expense (526 ) (524 ) Subtotal – Interest Rate and Foreign Currency (530 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (530 ) (527 ) Income Tax (Expense) Credit (186 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (344 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (10 ) (9 ) Interest Expense (1,574 ) (1,572 ) Subtotal – Interest Rate and Foreign Currency (1,584 ) (1,581 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,584 ) (1,743 ) Income Tax (Expense) Credit (554 ) (609 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,030 ) $ (1,134 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (291 ) (292 ) Subtotal – Interest Rate and Foreign Currency (291 ) (292 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (291 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (189 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (875 ) (876 ) Subtotal – Interest Rate and Foreign Currency (875 ) (876 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (875 ) (964 ) Income Tax (Expense) Credit (306 ) (338 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (569 ) $ (626 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 665 872 Subtotal – Interest Rate and Foreign Currency 665 872 Reclassifications from AOCI, before Income Tax (Expense) Credit 665 872 Income Tax (Expense) Credit 233 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 432 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (468 ) (478 ) Amortization of Actuarial (Gains)/Losses 99 118 Reclassifications from AOCI, before Income Tax (Expense) Credit (369 ) (360 ) Income Tax (Expense) Credit (129 ) (125 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (240 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 192 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 2,409 2,616 Subtotal – Interest Rate and Foreign Currency 2,409 2,616 Reclassifications from AOCI, before Income Tax (Expense) Credit 2,409 2,515 Income Tax (Expense) Credit 843 879 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,566 1,636 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,402 ) (1,433 ) Amortization of Actuarial (Gains)/Losses 296 351 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,106 ) (1,082 ) Income Tax (Expense) Credit (387 ) (378 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (719 ) (704 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 847 $ 932 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Ohio Power Co [Member] | |
Comprehensive Income | COMPREHENSIVE INCOME Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2015 and 2014 . All amounts in the following tables are presented net of related income taxes. APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — (222 ) (458 ) (680 ) Net Current Period Other Comprehensive Loss — (222 ) (458 ) (680 ) Balance in AOCI as of September 30, 2015 $ — $ 3,805 $ (238 ) $ 3,567 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 170 (333 ) (163 ) Net Current Period Other Comprehensive Income (Loss) — 170 (333 ) (163 ) Balance in AOCI as of September 30, 2014 $ — $ 3,766 $ (1,232 ) $ 2,534 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 3,896 $ 1,136 $ 5,032 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — (91 ) (1,374 ) (1,465 ) Net Current Period Other Comprehensive Loss — (91 ) (1,374 ) (1,465 ) Balance in AOCI as of September 30, 2015 $ — $ 3,805 $ (238 ) $ 3,567 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 94 $ 3,090 $ (233 ) $ 2,951 Change in Fair Value Recognized in AOCI 1,686 — — 1,686 Amounts Reclassified from AOCI (1,780 ) 676 (999 ) (2,103 ) Net Current Period Other Comprehensive Income (Loss) (94 ) 676 (999 ) (417 ) Balance in AOCI as of September 30, 2014 $ — $ 3,766 $ (1,232 ) $ 2,534 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 267 11 278 Net Current Period Other Comprehensive Income — 267 11 278 Balance in AOCI as of September 30, 2015 $ — $ (13,604 ) $ 79 $ (13,525 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 410 42 452 Net Current Period Other Comprehensive Income — 410 42 452 Balance in AOCI as of September 30, 2014 $ — $ (14,745 ) $ 549 $ (14,196 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (14,406 ) $ 46 $ (14,360 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 802 33 835 Net Current Period Other Comprehensive Income — 802 33 835 Balance in AOCI as of September 30, 2015 $ — $ (13,604 ) $ 79 $ (13,525 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 46 $ (15,976 ) $ 421 $ (15,509 ) Change in Fair Value Recognized in AOCI 1,130 — — 1,130 Amounts Reclassified from AOCI (1,176 ) 1,231 128 183 Net Current Period Other Comprehensive Income (Loss) (46 ) 1,231 128 1,313 Balance in AOCI as of September 30, 2014 $ — $ (14,745 ) $ 549 $ (14,196 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (344 ) (344 ) Net Current Period Other Comprehensive Loss — (344 ) (344 ) Balance in AOCI as of September 30, 2015 $ — $ 4,572 $ 4,572 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of September 30, 2014 $ — $ 5,945 $ 5,945 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 5,602 $ 5,602 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (1,030 ) (1,030 ) Net Current Period Other Comprehensive Loss — (1,030 ) (1,030 ) Balance in AOCI as of September 30, 2015 $ — $ 4,572 $ 4,572 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2013 $ 105 $ 6,974 $ 7,079 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (105 ) (1,029 ) (1,134 ) Net Current Period Other Comprehensive Loss (105 ) (1,029 ) (1,134 ) Balance in AOCI as of September 30, 2014 $ — $ 5,945 $ 5,945 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (189 ) (189 ) Net Current Period Other Comprehensive Loss — (189 ) (189 ) Balance in AOCI as of September 30, 2015 $ — $ 4,374 $ 4,374 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of September 30, 2014 $ — $ 5,132 $ 5,132 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 4,943 $ 4,943 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (569 ) (569 ) Net Current Period Other Comprehensive Loss — (569 ) (569 ) Balance in AOCI as of September 30, 2015 $ — $ 4,374 $ 4,374 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2013 $ 57 $ 5,701 $ 5,758 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (57 ) (569 ) (626 ) Net Current Period Other Comprehensive Loss (57 ) (569 ) (626 ) Balance in AOCI as of September 30, 2014 $ — $ 5,132 $ 5,132 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 432 (240 ) 192 Net Current Period Other Comprehensive Income (Loss) — 432 (240 ) 192 Balance in AOCI as of September 30, 2015 $ — $ (9,470 ) $ 2,851 $ (6,619 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (235 ) 332 Net Current Period Other Comprehensive Income (Loss) — 567 (235 ) 332 Balance in AOCI as of September 30, 2014 $ — $ (11,602 ) $ 4,090 $ (7,512 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (11,036 ) $ 3,570 $ (7,466 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 1,566 (719 ) 847 Net Current Period Other Comprehensive Income (Loss) — 1,566 (719 ) 847 Balance in AOCI as of September 30, 2015 $ — $ (9,470 ) $ 2,851 $ (6,619 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 66 $ (13,304 ) $ 4,794 $ (8,444 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI (66 ) 1,702 (704 ) 932 Net Current Period Other Comprehensive Income (Loss) (66 ) 1,702 (704 ) 932 Balance in AOCI as of September 30, 2014 $ — $ (11,602 ) $ 4,090 $ (7,512 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (342 ) 262 Subtotal – Interest Rate and Foreign Currency (342 ) 262 Reclassifications from AOCI, before Income Tax (Expense) Credit (342 ) 262 Income Tax (Expense) Credit (120 ) 92 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (222 ) 170 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,282 ) (1,281 ) Amortization of Actuarial (Gains)/Losses 577 769 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (512 ) Income Tax (Expense) Credit (247 ) (179 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (680 ) $ (163 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense (140 ) 1,042 Subtotal – Interest Rate and Foreign Currency (140 ) 1,042 Reclassifications from AOCI, before Income Tax (Expense) Credit (140 ) (1,696 ) Income Tax (Expense) Credit (49 ) (592 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (91 ) (1,104 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (3,847 ) (3,846 ) Amortization of Actuarial (Gains)/Losses 1,733 2,309 Reclassifications from AOCI, before Income Tax (Expense) Credit (2,114 ) (1,537 ) Income Tax (Expense) Credit (740 ) (538 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1,374 ) (999 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,465 ) $ (2,103 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 412 631 Subtotal – Interest Rate and Foreign Currency 412 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 412 631 Income Tax (Expense) Credit 145 221 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 267 410 Pension and OPEB Amortization of Prior Service Cost (Credit) (198 ) (200 ) Amortization of Actuarial (Gains)/Losses 215 264 Reclassifications from AOCI, before Income Tax (Expense) Credit 17 64 Income Tax (Expense) Credit 6 22 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11 42 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 452 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 1,234 1,893 Subtotal – Interest Rate and Foreign Currency 1,234 1,893 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,234 84 Income Tax (Expense) Credit 432 29 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 802 55 Pension and OPEB Amortization of Prior Service Cost (Credit) (596 ) (597 ) Amortization of Actuarial (Gains)/Losses 647 791 Reclassifications from AOCI, before Income Tax (Expense) Credit 51 194 Income Tax (Expense) Credit 18 66 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 33 128 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 835 $ 183 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (4 ) (3 ) Interest Expense (526 ) (524 ) Subtotal – Interest Rate and Foreign Currency (530 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (530 ) (527 ) Income Tax (Expense) Credit (186 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (344 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (10 ) (9 ) Interest Expense (1,574 ) (1,572 ) Subtotal – Interest Rate and Foreign Currency (1,584 ) (1,581 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,584 ) (1,743 ) Income Tax (Expense) Credit (554 ) (609 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,030 ) $ (1,134 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (291 ) (292 ) Subtotal – Interest Rate and Foreign Currency (291 ) (292 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (291 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (189 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (875 ) (876 ) Subtotal – Interest Rate and Foreign Currency (875 ) (876 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (875 ) (964 ) Income Tax (Expense) Credit (306 ) (338 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (569 ) $ (626 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 665 872 Subtotal – Interest Rate and Foreign Currency 665 872 Reclassifications from AOCI, before Income Tax (Expense) Credit 665 872 Income Tax (Expense) Credit 233 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 432 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (468 ) (478 ) Amortization of Actuarial (Gains)/Losses 99 118 Reclassifications from AOCI, before Income Tax (Expense) Credit (369 ) (360 ) Income Tax (Expense) Credit (129 ) (125 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (240 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 192 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 2,409 2,616 Subtotal – Interest Rate and Foreign Currency 2,409 2,616 Reclassifications from AOCI, before Income Tax (Expense) Credit 2,409 2,515 Income Tax (Expense) Credit 843 879 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,566 1,636 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,402 ) (1,433 ) Amortization of Actuarial (Gains)/Losses 296 351 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,106 ) (1,082 ) Income Tax (Expense) Credit (387 ) (378 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (719 ) (704 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 847 $ 932 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Public Service Co Of Oklahoma [Member] | |
Comprehensive Income | COMPREHENSIVE INCOME Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2015 and 2014 . All amounts in the following tables are presented net of related income taxes. APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — (222 ) (458 ) (680 ) Net Current Period Other Comprehensive Loss — (222 ) (458 ) (680 ) Balance in AOCI as of September 30, 2015 $ — $ 3,805 $ (238 ) $ 3,567 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 170 (333 ) (163 ) Net Current Period Other Comprehensive Income (Loss) — 170 (333 ) (163 ) Balance in AOCI as of September 30, 2014 $ — $ 3,766 $ (1,232 ) $ 2,534 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 3,896 $ 1,136 $ 5,032 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — (91 ) (1,374 ) (1,465 ) Net Current Period Other Comprehensive Loss — (91 ) (1,374 ) (1,465 ) Balance in AOCI as of September 30, 2015 $ — $ 3,805 $ (238 ) $ 3,567 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 94 $ 3,090 $ (233 ) $ 2,951 Change in Fair Value Recognized in AOCI 1,686 — — 1,686 Amounts Reclassified from AOCI (1,780 ) 676 (999 ) (2,103 ) Net Current Period Other Comprehensive Income (Loss) (94 ) 676 (999 ) (417 ) Balance in AOCI as of September 30, 2014 $ — $ 3,766 $ (1,232 ) $ 2,534 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 267 11 278 Net Current Period Other Comprehensive Income — 267 11 278 Balance in AOCI as of September 30, 2015 $ — $ (13,604 ) $ 79 $ (13,525 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 410 42 452 Net Current Period Other Comprehensive Income — 410 42 452 Balance in AOCI as of September 30, 2014 $ — $ (14,745 ) $ 549 $ (14,196 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (14,406 ) $ 46 $ (14,360 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 802 33 835 Net Current Period Other Comprehensive Income — 802 33 835 Balance in AOCI as of September 30, 2015 $ — $ (13,604 ) $ 79 $ (13,525 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 46 $ (15,976 ) $ 421 $ (15,509 ) Change in Fair Value Recognized in AOCI 1,130 — — 1,130 Amounts Reclassified from AOCI (1,176 ) 1,231 128 183 Net Current Period Other Comprehensive Income (Loss) (46 ) 1,231 128 1,313 Balance in AOCI as of September 30, 2014 $ — $ (14,745 ) $ 549 $ (14,196 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (344 ) (344 ) Net Current Period Other Comprehensive Loss — (344 ) (344 ) Balance in AOCI as of September 30, 2015 $ — $ 4,572 $ 4,572 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of September 30, 2014 $ — $ 5,945 $ 5,945 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 5,602 $ 5,602 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (1,030 ) (1,030 ) Net Current Period Other Comprehensive Loss — (1,030 ) (1,030 ) Balance in AOCI as of September 30, 2015 $ — $ 4,572 $ 4,572 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2013 $ 105 $ 6,974 $ 7,079 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (105 ) (1,029 ) (1,134 ) Net Current Period Other Comprehensive Loss (105 ) (1,029 ) (1,134 ) Balance in AOCI as of September 30, 2014 $ — $ 5,945 $ 5,945 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (189 ) (189 ) Net Current Period Other Comprehensive Loss — (189 ) (189 ) Balance in AOCI as of September 30, 2015 $ — $ 4,374 $ 4,374 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of September 30, 2014 $ — $ 5,132 $ 5,132 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 4,943 $ 4,943 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (569 ) (569 ) Net Current Period Other Comprehensive Loss — (569 ) (569 ) Balance in AOCI as of September 30, 2015 $ — $ 4,374 $ 4,374 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2013 $ 57 $ 5,701 $ 5,758 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (57 ) (569 ) (626 ) Net Current Period Other Comprehensive Loss (57 ) (569 ) (626 ) Balance in AOCI as of September 30, 2014 $ — $ 5,132 $ 5,132 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 432 (240 ) 192 Net Current Period Other Comprehensive Income (Loss) — 432 (240 ) 192 Balance in AOCI as of September 30, 2015 $ — $ (9,470 ) $ 2,851 $ (6,619 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (235 ) 332 Net Current Period Other Comprehensive Income (Loss) — 567 (235 ) 332 Balance in AOCI as of September 30, 2014 $ — $ (11,602 ) $ 4,090 $ (7,512 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (11,036 ) $ 3,570 $ (7,466 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 1,566 (719 ) 847 Net Current Period Other Comprehensive Income (Loss) — 1,566 (719 ) 847 Balance in AOCI as of September 30, 2015 $ — $ (9,470 ) $ 2,851 $ (6,619 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 66 $ (13,304 ) $ 4,794 $ (8,444 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI (66 ) 1,702 (704 ) 932 Net Current Period Other Comprehensive Income (Loss) (66 ) 1,702 (704 ) 932 Balance in AOCI as of September 30, 2014 $ — $ (11,602 ) $ 4,090 $ (7,512 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (342 ) 262 Subtotal – Interest Rate and Foreign Currency (342 ) 262 Reclassifications from AOCI, before Income Tax (Expense) Credit (342 ) 262 Income Tax (Expense) Credit (120 ) 92 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (222 ) 170 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,282 ) (1,281 ) Amortization of Actuarial (Gains)/Losses 577 769 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (512 ) Income Tax (Expense) Credit (247 ) (179 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (680 ) $ (163 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense (140 ) 1,042 Subtotal – Interest Rate and Foreign Currency (140 ) 1,042 Reclassifications from AOCI, before Income Tax (Expense) Credit (140 ) (1,696 ) Income Tax (Expense) Credit (49 ) (592 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (91 ) (1,104 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (3,847 ) (3,846 ) Amortization of Actuarial (Gains)/Losses 1,733 2,309 Reclassifications from AOCI, before Income Tax (Expense) Credit (2,114 ) (1,537 ) Income Tax (Expense) Credit (740 ) (538 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1,374 ) (999 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,465 ) $ (2,103 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 412 631 Subtotal – Interest Rate and Foreign Currency 412 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 412 631 Income Tax (Expense) Credit 145 221 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 267 410 Pension and OPEB Amortization of Prior Service Cost (Credit) (198 ) (200 ) Amortization of Actuarial (Gains)/Losses 215 264 Reclassifications from AOCI, before Income Tax (Expense) Credit 17 64 Income Tax (Expense) Credit 6 22 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11 42 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 452 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 1,234 1,893 Subtotal – Interest Rate and Foreign Currency 1,234 1,893 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,234 84 Income Tax (Expense) Credit 432 29 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 802 55 Pension and OPEB Amortization of Prior Service Cost (Credit) (596 ) (597 ) Amortization of Actuarial (Gains)/Losses 647 791 Reclassifications from AOCI, before Income Tax (Expense) Credit 51 194 Income Tax (Expense) Credit 18 66 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 33 128 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 835 $ 183 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (4 ) (3 ) Interest Expense (526 ) (524 ) Subtotal – Interest Rate and Foreign Currency (530 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (530 ) (527 ) Income Tax (Expense) Credit (186 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (344 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (10 ) (9 ) Interest Expense (1,574 ) (1,572 ) Subtotal – Interest Rate and Foreign Currency (1,584 ) (1,581 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,584 ) (1,743 ) Income Tax (Expense) Credit (554 ) (609 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,030 ) $ (1,134 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (291 ) (292 ) Subtotal – Interest Rate and Foreign Currency (291 ) (292 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (291 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (189 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (875 ) (876 ) Subtotal – Interest Rate and Foreign Currency (875 ) (876 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (875 ) (964 ) Income Tax (Expense) Credit (306 ) (338 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (569 ) $ (626 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 665 872 Subtotal – Interest Rate and Foreign Currency 665 872 Reclassifications from AOCI, before Income Tax (Expense) Credit 665 872 Income Tax (Expense) Credit 233 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 432 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (468 ) (478 ) Amortization of Actuarial (Gains)/Losses 99 118 Reclassifications from AOCI, before Income Tax (Expense) Credit (369 ) (360 ) Income Tax (Expense) Credit (129 ) (125 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (240 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 192 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 2,409 2,616 Subtotal – Interest Rate and Foreign Currency 2,409 2,616 Reclassifications from AOCI, before Income Tax (Expense) Credit 2,409 2,515 Income Tax (Expense) Credit 843 879 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,566 1,636 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,402 ) (1,433 ) Amortization of Actuarial (Gains)/Losses 296 351 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,106 ) (1,082 ) Income Tax (Expense) Credit (387 ) (378 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (719 ) (704 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 847 $ 932 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Southwestern Electric Power Co [Member] | |
Comprehensive Income | COMPREHENSIVE INCOME Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2015 and 2014 . All amounts in the following tables are presented net of related income taxes. APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — (222 ) (458 ) (680 ) Net Current Period Other Comprehensive Loss — (222 ) (458 ) (680 ) Balance in AOCI as of September 30, 2015 $ — $ 3,805 $ (238 ) $ 3,567 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 170 (333 ) (163 ) Net Current Period Other Comprehensive Income (Loss) — 170 (333 ) (163 ) Balance in AOCI as of September 30, 2014 $ — $ 3,766 $ (1,232 ) $ 2,534 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 3,896 $ 1,136 $ 5,032 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — (91 ) (1,374 ) (1,465 ) Net Current Period Other Comprehensive Loss — (91 ) (1,374 ) (1,465 ) Balance in AOCI as of September 30, 2015 $ — $ 3,805 $ (238 ) $ 3,567 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 94 $ 3,090 $ (233 ) $ 2,951 Change in Fair Value Recognized in AOCI 1,686 — — 1,686 Amounts Reclassified from AOCI (1,780 ) 676 (999 ) (2,103 ) Net Current Period Other Comprehensive Income (Loss) (94 ) 676 (999 ) (417 ) Balance in AOCI as of September 30, 2014 $ — $ 3,766 $ (1,232 ) $ 2,534 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 267 11 278 Net Current Period Other Comprehensive Income — 267 11 278 Balance in AOCI as of September 30, 2015 $ — $ (13,604 ) $ 79 $ (13,525 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 410 42 452 Net Current Period Other Comprehensive Income — 410 42 452 Balance in AOCI as of September 30, 2014 $ — $ (14,745 ) $ 549 $ (14,196 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (14,406 ) $ 46 $ (14,360 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 802 33 835 Net Current Period Other Comprehensive Income — 802 33 835 Balance in AOCI as of September 30, 2015 $ — $ (13,604 ) $ 79 $ (13,525 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 46 $ (15,976 ) $ 421 $ (15,509 ) Change in Fair Value Recognized in AOCI 1,130 — — 1,130 Amounts Reclassified from AOCI (1,176 ) 1,231 128 183 Net Current Period Other Comprehensive Income (Loss) (46 ) 1,231 128 1,313 Balance in AOCI as of September 30, 2014 $ — $ (14,745 ) $ 549 $ (14,196 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (344 ) (344 ) Net Current Period Other Comprehensive Loss — (344 ) (344 ) Balance in AOCI as of September 30, 2015 $ — $ 4,572 $ 4,572 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of September 30, 2014 $ — $ 5,945 $ 5,945 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 5,602 $ 5,602 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (1,030 ) (1,030 ) Net Current Period Other Comprehensive Loss — (1,030 ) (1,030 ) Balance in AOCI as of September 30, 2015 $ — $ 4,572 $ 4,572 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2013 $ 105 $ 6,974 $ 7,079 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (105 ) (1,029 ) (1,134 ) Net Current Period Other Comprehensive Loss (105 ) (1,029 ) (1,134 ) Balance in AOCI as of September 30, 2014 $ — $ 5,945 $ 5,945 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (189 ) (189 ) Net Current Period Other Comprehensive Loss — (189 ) (189 ) Balance in AOCI as of September 30, 2015 $ — $ 4,374 $ 4,374 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of September 30, 2014 $ — $ 5,132 $ 5,132 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 4,943 $ 4,943 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (569 ) (569 ) Net Current Period Other Comprehensive Loss — (569 ) (569 ) Balance in AOCI as of September 30, 2015 $ — $ 4,374 $ 4,374 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2013 $ 57 $ 5,701 $ 5,758 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (57 ) (569 ) (626 ) Net Current Period Other Comprehensive Loss (57 ) (569 ) (626 ) Balance in AOCI as of September 30, 2014 $ — $ 5,132 $ 5,132 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 432 (240 ) 192 Net Current Period Other Comprehensive Income (Loss) — 432 (240 ) 192 Balance in AOCI as of September 30, 2015 $ — $ (9,470 ) $ 2,851 $ (6,619 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (235 ) 332 Net Current Period Other Comprehensive Income (Loss) — 567 (235 ) 332 Balance in AOCI as of September 30, 2014 $ — $ (11,602 ) $ 4,090 $ (7,512 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (11,036 ) $ 3,570 $ (7,466 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 1,566 (719 ) 847 Net Current Period Other Comprehensive Income (Loss) — 1,566 (719 ) 847 Balance in AOCI as of September 30, 2015 $ — $ (9,470 ) $ 2,851 $ (6,619 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 66 $ (13,304 ) $ 4,794 $ (8,444 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI (66 ) 1,702 (704 ) 932 Net Current Period Other Comprehensive Income (Loss) (66 ) 1,702 (704 ) 932 Balance in AOCI as of September 30, 2014 $ — $ (11,602 ) $ 4,090 $ (7,512 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (342 ) 262 Subtotal – Interest Rate and Foreign Currency (342 ) 262 Reclassifications from AOCI, before Income Tax (Expense) Credit (342 ) 262 Income Tax (Expense) Credit (120 ) 92 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (222 ) 170 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,282 ) (1,281 ) Amortization of Actuarial (Gains)/Losses 577 769 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (512 ) Income Tax (Expense) Credit (247 ) (179 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (680 ) $ (163 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense (140 ) 1,042 Subtotal – Interest Rate and Foreign Currency (140 ) 1,042 Reclassifications from AOCI, before Income Tax (Expense) Credit (140 ) (1,696 ) Income Tax (Expense) Credit (49 ) (592 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (91 ) (1,104 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (3,847 ) (3,846 ) Amortization of Actuarial (Gains)/Losses 1,733 2,309 Reclassifications from AOCI, before Income Tax (Expense) Credit (2,114 ) (1,537 ) Income Tax (Expense) Credit (740 ) (538 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1,374 ) (999 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,465 ) $ (2,103 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 412 631 Subtotal – Interest Rate and Foreign Currency 412 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 412 631 Income Tax (Expense) Credit 145 221 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 267 410 Pension and OPEB Amortization of Prior Service Cost (Credit) (198 ) (200 ) Amortization of Actuarial (Gains)/Losses 215 264 Reclassifications from AOCI, before Income Tax (Expense) Credit 17 64 Income Tax (Expense) Credit 6 22 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11 42 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 452 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 1,234 1,893 Subtotal – Interest Rate and Foreign Currency 1,234 1,893 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,234 84 Income Tax (Expense) Credit 432 29 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 802 55 Pension and OPEB Amortization of Prior Service Cost (Credit) (596 ) (597 ) Amortization of Actuarial (Gains)/Losses 647 791 Reclassifications from AOCI, before Income Tax (Expense) Credit 51 194 Income Tax (Expense) Credit 18 66 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 33 128 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 835 $ 183 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (4 ) (3 ) Interest Expense (526 ) (524 ) Subtotal – Interest Rate and Foreign Currency (530 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (530 ) (527 ) Income Tax (Expense) Credit (186 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (344 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (10 ) (9 ) Interest Expense (1,574 ) (1,572 ) Subtotal – Interest Rate and Foreign Currency (1,584 ) (1,581 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,584 ) (1,743 ) Income Tax (Expense) Credit (554 ) (609 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,030 ) $ (1,134 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (291 ) (292 ) Subtotal – Interest Rate and Foreign Currency (291 ) (292 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (291 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (189 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (875 ) (876 ) Subtotal – Interest Rate and Foreign Currency (875 ) (876 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (875 ) (964 ) Income Tax (Expense) Credit (306 ) (338 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (569 ) $ (626 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 665 872 Subtotal – Interest Rate and Foreign Currency 665 872 Reclassifications from AOCI, before Income Tax (Expense) Credit 665 872 Income Tax (Expense) Credit 233 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 432 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (468 ) (478 ) Amortization of Actuarial (Gains)/Losses 99 118 Reclassifications from AOCI, before Income Tax (Expense) Credit (369 ) (360 ) Income Tax (Expense) Credit (129 ) (125 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (240 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 192 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 2,409 2,616 Subtotal – Interest Rate and Foreign Currency 2,409 2,616 Reclassifications from AOCI, before Income Tax (Expense) Credit 2,409 2,515 Income Tax (Expense) Credit 843 879 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,566 1,636 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,402 ) (1,433 ) Amortization of Actuarial (Gains)/Losses 296 351 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,106 ) (1,082 ) Income Tax (Expense) Credit (387 ) (378 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (719 ) (704 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 847 $ 932 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Rate Matters
Rate Matters | 9 Months Ended |
Sep. 30, 2015 | |
Rate Matters | RATE MATTERS As discussed in the 2014 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2014 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2015 and updates the 2014 Annual Report. Regulatory Assets Pending Final Regulatory Approval September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Storm Related Costs $ 24 $ 20 Material and Supplies Related to Retired Plants 20 — West Virginia Vegetation Management Program — 20 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 59 — Virginia Peak Demand Reduction/Energy Efficiency 12 9 Ormet Special Rate Recovery Mechanism 10 10 Storm Related Costs 7 100 Carbon Capture and Storage Product Validation Facility — 13 IGCC Pre-Construction Costs — 11 Other Regulatory Assets Pending Final Regulatory Approval 27 43 Total Regulatory Assets Pending Final Regulatory Approval $ 159 $ 226 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters Ohio Electric Security Plan Filings 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio, which has scheduled oral arguments for the fourth quarter of 2015. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015 , OPCo's net deferred capacity costs balance of $392 million , including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. Through September 30, 2015 , OPCo has collected $183 million in deferred capacity costs, and related carrying charges. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. June 2015 - May 2018 ESP Including PPA Application In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of September 30, 2015 , is recorded in Regulatory Assets on the condensed balance sheet. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement was held in May 2014. In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of September 30, 2015 , the net book value of Welsh Plant, Unit 2 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million . In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC review base rates in 2014 and 2015 and that SWEPCo recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million , primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2014 Louisiana Formula Rate Filing In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase, which was effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million . This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant, Units 1 and 3 – Environmental Projects To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million , excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million , excluding AFUDC. As of September 30, 2015 , SWEPCo has incurred costs of $303 million , including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of September 30, 2015 , the net book value of Welsh Plant, Units 1 and 3 was $529 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. APCo and WPCo Rate Matters 2014 West Virginia Base Rate Case In May 2015, the WVPSC issued an order on APCo and WPCo's base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $99 million based upon a 9.75% return on common equity. The order included a delayed billing of $25 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $25 million delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $45 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $89 million in previously recorded regulatory assets, which will predominantly be recovered over five years. 2015 Virginia Regulatory Asset Proceeding In January 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets. In February and March 2015, briefs related to this proceeding were filed by various parties. As of September 30, 2015 , APCo’s authorized regulatory assets under review in this proceeding were $11 million . If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. New Virginia Legislation Affecting Biennial Reviews In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. PSO Rate Matters 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of September 30, 2015 , PSO has incurred costs of $162 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million , will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of September 30, 2015 , the net book value of Northeastern Plant, Unit 4 was $94 million , before cost of removal, including materials and supplies inventory and CWIP. In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million , based upon returns on common equity ranging from 8.75% to 9.3% , and increases to depreciation expense ranging from $23 million to $46 million . Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC are scheduled for December 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. I&M Rate Matters Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million . In April 2015, I&M filed a notice with the IURC to exclude $117 million related to certain projects. In September 2015, the IURC granted I&M's motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals. KPCo Rate Matters Plant Transfer In October 2013, the KPSC issued an order that approved a modified settlement agreement which included the approval to transfer to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. In December 2013, the Attorney General filed an appeal of the order with the Franklin County Circuit Court. In April 2015, the Franklin County Circuit Court issued an order that affirmed the KPSC's October 2013 order. In May 2015, the Attorney General filed an appeal with the Franklin County Circuit Court of the April 2015 order that had affirmed the KPSC's order. Consistent with KPCo’s December 2012 plant transfer filing that was approved by the KPSC, Big Sandy Plant, Unit 2 was retired in May 2015. Upon retirement, $194 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Big Sandy Plant, Unit 2 and the related asset retirement obligations, costs of removal and materials and supplies. These regulatory assets will be amortized over 25 years, effective July 2015. If any part of the KPSC order is overturned, it could reduce future net income and cash flows and impact financial condition. Kentucky Fuel Adjustment Clause Review In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court. In September 2015, the Franklin County Circuit Court issued an order that dismissed all appeals filed related to this FAC review, as agreed to by the parties to the stipulation agreement in the "2014 Kentucky Base Rate Case" discussed below. 2014 Kentucky Base Rate Case In December 2014, KPCo filed a request with the KPSC for a net increase in rates of $70 million . In April 2015, a non-unanimous stipulation agreement between KPCo and certain intervenors was filed with the KPSC. The parties to the stipulation recommended a net revenue increase of $45 million , which consisted of a $68 million increase in rider rates, offset by a $23 million decrease in annual base rates, to be effective July 2015. The proposed net increase reflects KPCo's ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan. Additionally, the agreement included (a) recovery of $12 million of deferred storm costs, (b) any difference between the actual off-system sales margins and the $15 million included in the proposed annual base rates to be shared with 75% to the customer and 25% to KPCo and (c) dismissal of the KPCo and the Kentucky Industrial Utility Customers appeals of the KPSC order in the KPCo fuel adjustment |
Appalachian Power Co [Member] | |
Rate Matters | RATE MATTERS As discussed in the 2014 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2014 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2015 and updates the 2014 Annual Report. Regulatory Assets Pending Final Regulatory Approval APCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 8,592 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 32,128 — Peak Demand Reduction/Energy Efficiency – Virginia 11,650 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Deferred Permit Fees Related to Retired Plants – West Virginia 617 — Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory – West Virginia — 3,421 Expanded Net Energy Charge – Construction Surcharge – West Virginia — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval — 168 Total Regulatory Assets Pending Final Regulatory Approval $ 54,937 $ 125,748 I&M September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,652 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,955 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 3,445 1,222 Rockport Dry Sorbent Injection System 1,865 148 Storm Related Costs – Indiana — 1,074 Other Regulatory Assets Pending Final Regulatory Approval 11 712 Total Regulatory Assets Pending Final Regulatory Approval $ 56,904 $ 13,649 OPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Total Regulatory Assets Pending Final Regulatory Approval $ 10,483 $ 10,483 PSO September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project $ 3,031 $ 2,287 Asset Retirement Obligation 1,516 1,144 Rate Case Expenses — 8,126 Other Regulatory Assets Pending Final Regulatory Approval 695 558 Total Regulatory Assets Pending Final Regulatory Approval $ 5,242 $ 12,115 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters Ohio Electric Security Plan Filings 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio, which has scheduled oral arguments for the fourth quarter of 2015. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015 , OPCo's net deferred capacity costs balance of $392 million , including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. Through September 30, 2015 , OPCo has collected $183 million in deferred capacity costs, and related carrying charges. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. June 2015 - May 2018 ESP Including PPA Application In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of September 30, 2015 , is recorded in Regulatory Assets on the condensed balance sheet. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement was held in May 2014. In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of September 30, 2015 , the net book value of Welsh Plant, Unit 2 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million . In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC review base rates in 2014 and 2015 and that SWEPCo recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million , primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2014 Louisiana Formula Rate Filing In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase, which was effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million . This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant, Units 1 and 3 – Environmental Projects To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million , excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million , excluding AFUDC. As of September 30, 2015 , SWEPCo has incurred costs of $303 million , including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of September 30, 2015 , the net book value of Welsh Plant, Units 1 and 3 was $529 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. APCo Rate Matters 2014 West Virginia Base Rate Case In May 2015, the WVPSC issued an order on APCo's base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $85 million based upon a 9.75% return on common equity. The order included a delayed billing of $22 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $22 million delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $38 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $77 million in previously recorded regulatory assets, which will predominantly be recovered over five years. 2015 Virginia Regulatory Asset Proceeding In January 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets. In February and March 2015, briefs related to this proceeding were filed by various parties. As of September 30, 2015 , APCo’s authorized regulatory assets under review in this proceeding were $11 million . If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. New Virginia Legislation Affecting Biennial Reviews In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. PSO Rate Matters 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of September 30, 2015 , PSO has incurred costs of $162 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million , will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of September 30, 2015 , the net book value of Northeastern Plant, Unit 4 was $94 million , before cost of removal, including materials and supplies inventory and CWIP. In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million , based upon returns on common equity ranging from 8.75% to 9.3% , and increases to depreciation expense ranging from $23 million to $46 million . Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC are scheduled for December 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. I&M Rate Matters Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million . In April 2015, I&M filed a notice with the IURC to exclude $117 million related to certain projects. In September 2015, the IURC granted I&M's motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals. |
Indiana Michigan Power Co [Member] | |
Rate Matters | RATE MATTERS As discussed in the 2014 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2014 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2015 and updates the 2014 Annual Report. Regulatory Assets Pending Final Regulatory Approval APCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 8,592 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 32,128 — Peak Demand Reduction/Energy Efficiency – Virginia 11,650 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Deferred Permit Fees Related to Retired Plants – West Virginia 617 — Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory – West Virginia — 3,421 Expanded Net Energy Charge – Construction Surcharge – West Virginia — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval — 168 Total Regulatory Assets Pending Final Regulatory Approval $ 54,937 $ 125,748 I&M September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,652 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,955 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 3,445 1,222 Rockport Dry Sorbent Injection System 1,865 148 Storm Related Costs – Indiana — 1,074 Other Regulatory Assets Pending Final Regulatory Approval 11 712 Total Regulatory Assets Pending Final Regulatory Approval $ 56,904 $ 13,649 OPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Total Regulatory Assets Pending Final Regulatory Approval $ 10,483 $ 10,483 PSO September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project $ 3,031 $ 2,287 Asset Retirement Obligation 1,516 1,144 Rate Case Expenses — 8,126 Other Regulatory Assets Pending Final Regulatory Approval 695 558 Total Regulatory Assets Pending Final Regulatory Approval $ 5,242 $ 12,115 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters Ohio Electric Security Plan Filings 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio, which has scheduled oral arguments for the fourth quarter of 2015. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015 , OPCo's net deferred capacity costs balance of $392 million , including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. Through September 30, 2015 , OPCo has collected $183 million in deferred capacity costs, and related carrying charges. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. June 2015 - May 2018 ESP Including PPA Application In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of September 30, 2015 , is recorded in Regulatory Assets on the condensed balance sheet. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement was held in May 2014. In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of September 30, 2015 , the net book value of Welsh Plant, Unit 2 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million . In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC review base rates in 2014 and 2015 and that SWEPCo recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million , primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2014 Louisiana Formula Rate Filing In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase, which was effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million . This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant, Units 1 and 3 – Environmental Projects To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million , excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million , excluding AFUDC. As of September 30, 2015 , SWEPCo has incurred costs of $303 million , including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of September 30, 2015 , the net book value of Welsh Plant, Units 1 and 3 was $529 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. APCo Rate Matters 2014 West Virginia Base Rate Case In May 2015, the WVPSC issued an order on APCo's base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $85 million based upon a 9.75% return on common equity. The order included a delayed billing of $22 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $22 million delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $38 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $77 million in previously recorded regulatory assets, which will predominantly be recovered over five years. 2015 Virginia Regulatory Asset Proceeding In January 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets. In February and March 2015, briefs related to this proceeding were filed by various parties. As of September 30, 2015 , APCo’s authorized regulatory assets under review in this proceeding were $11 million . If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. New Virginia Legislation Affecting Biennial Reviews In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. PSO Rate Matters 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of September 30, 2015 , PSO has incurred costs of $162 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million , will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of September 30, 2015 , the net book value of Northeastern Plant, Unit 4 was $94 million , before cost of removal, including materials and supplies inventory and CWIP. In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million , based upon returns on common equity ranging from 8.75% to 9.3% , and increases to depreciation expense ranging from $23 million to $46 million . Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC are scheduled for December 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. I&M Rate Matters Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million . In April 2015, I&M filed a notice with the IURC to exclude $117 million related to certain projects. In September 2015, the IURC granted I&M's motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals. |
Ohio Power Co [Member] | |
Rate Matters | RATE MATTERS As discussed in the 2014 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2014 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2015 and updates the 2014 Annual Report. Regulatory Assets Pending Final Regulatory Approval APCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 8,592 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 32,128 — Peak Demand Reduction/Energy Efficiency – Virginia 11,650 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Deferred Permit Fees Related to Retired Plants – West Virginia 617 — Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory – West Virginia — 3,421 Expanded Net Energy Charge – Construction Surcharge – West Virginia — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval — 168 Total Regulatory Assets Pending Final Regulatory Approval $ 54,937 $ 125,748 I&M September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,652 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,955 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 3,445 1,222 Rockport Dry Sorbent Injection System 1,865 148 Storm Related Costs – Indiana — 1,074 Other Regulatory Assets Pending Final Regulatory Approval 11 712 Total Regulatory Assets Pending Final Regulatory Approval $ 56,904 $ 13,649 OPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Total Regulatory Assets Pending Final Regulatory Approval $ 10,483 $ 10,483 PSO September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project $ 3,031 $ 2,287 Asset Retirement Obligation 1,516 1,144 Rate Case Expenses — 8,126 Other Regulatory Assets Pending Final Regulatory Approval 695 558 Total Regulatory Assets Pending Final Regulatory Approval $ 5,242 $ 12,115 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters Ohio Electric Security Plan Filings 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio, which has scheduled oral arguments for the fourth quarter of 2015. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015 , OPCo's net deferred capacity costs balance of $392 million , including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. Through September 30, 2015 , OPCo has collected $183 million in deferred capacity costs, and related carrying charges. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. June 2015 - May 2018 ESP Including PPA Application In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of September 30, 2015 , is recorded in Regulatory Assets on the condensed balance sheet. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement was held in May 2014. In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of September 30, 2015 , the net book value of Welsh Plant, Unit 2 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million . In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC review base rates in 2014 and 2015 and that SWEPCo recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million , primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2014 Louisiana Formula Rate Filing In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase, which was effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million . This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant, Units 1 and 3 – Environmental Projects To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million , excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million , excluding AFUDC. As of September 30, 2015 , SWEPCo has incurred costs of $303 million , including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of September 30, 2015 , the net book value of Welsh Plant, Units 1 and 3 was $529 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. APCo Rate Matters 2014 West Virginia Base Rate Case In May 2015, the WVPSC issued an order on APCo's base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $85 million based upon a 9.75% return on common equity. The order included a delayed billing of $22 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $22 million delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $38 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $77 million in previously recorded regulatory assets, which will predominantly be recovered over five years. 2015 Virginia Regulatory Asset Proceeding In January 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets. In February and March 2015, briefs related to this proceeding were filed by various parties. As of September 30, 2015 , APCo’s authorized regulatory assets under review in this proceeding were $11 million . If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. New Virginia Legislation Affecting Biennial Reviews In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. PSO Rate Matters 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of September 30, 2015 , PSO has incurred costs of $162 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million , will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of September 30, 2015 , the net book value of Northeastern Plant, Unit 4 was $94 million , before cost of removal, including materials and supplies inventory and CWIP. In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million , based upon returns on common equity ranging from 8.75% to 9.3% , and increases to depreciation expense ranging from $23 million to $46 million . Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC are scheduled for December 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. I&M Rate Matters Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million . In April 2015, I&M filed a notice with the IURC to exclude $117 million related to certain projects. In September 2015, the IURC granted I&M's motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals. |
Public Service Co Of Oklahoma [Member] | |
Rate Matters | RATE MATTERS As discussed in the 2014 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2014 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2015 and updates the 2014 Annual Report. Regulatory Assets Pending Final Regulatory Approval APCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 8,592 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 32,128 — Peak Demand Reduction/Energy Efficiency – Virginia 11,650 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Deferred Permit Fees Related to Retired Plants – West Virginia 617 — Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory – West Virginia — 3,421 Expanded Net Energy Charge – Construction Surcharge – West Virginia — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval — 168 Total Regulatory Assets Pending Final Regulatory Approval $ 54,937 $ 125,748 I&M September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,652 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,955 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 3,445 1,222 Rockport Dry Sorbent Injection System 1,865 148 Storm Related Costs – Indiana — 1,074 Other Regulatory Assets Pending Final Regulatory Approval 11 712 Total Regulatory Assets Pending Final Regulatory Approval $ 56,904 $ 13,649 OPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Total Regulatory Assets Pending Final Regulatory Approval $ 10,483 $ 10,483 PSO September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project $ 3,031 $ 2,287 Asset Retirement Obligation 1,516 1,144 Rate Case Expenses — 8,126 Other Regulatory Assets Pending Final Regulatory Approval 695 558 Total Regulatory Assets Pending Final Regulatory Approval $ 5,242 $ 12,115 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters Ohio Electric Security Plan Filings 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio, which has scheduled oral arguments for the fourth quarter of 2015. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015 , OPCo's net deferred capacity costs balance of $392 million , including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. Through September 30, 2015 , OPCo has collected $183 million in deferred capacity costs, and related carrying charges. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. June 2015 - May 2018 ESP Including PPA Application In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of September 30, 2015 , is recorded in Regulatory Assets on the condensed balance sheet. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement was held in May 2014. In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of September 30, 2015 , the net book value of Welsh Plant, Unit 2 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million . In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC review base rates in 2014 and 2015 and that SWEPCo recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million , primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2014 Louisiana Formula Rate Filing In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase, which was effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million . This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant, Units 1 and 3 – Environmental Projects To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million , excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million , excluding AFUDC. As of September 30, 2015 , SWEPCo has incurred costs of $303 million , including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of September 30, 2015 , the net book value of Welsh Plant, Units 1 and 3 was $529 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. APCo Rate Matters 2014 West Virginia Base Rate Case In May 2015, the WVPSC issued an order on APCo's base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $85 million based upon a 9.75% return on common equity. The order included a delayed billing of $22 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $22 million delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $38 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $77 million in previously recorded regulatory assets, which will predominantly be recovered over five years. 2015 Virginia Regulatory Asset Proceeding In January 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets. In February and March 2015, briefs related to this proceeding were filed by various parties. As of September 30, 2015 , APCo’s authorized regulatory assets under review in this proceeding were $11 million . If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. New Virginia Legislation Affecting Biennial Reviews In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. PSO Rate Matters 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of September 30, 2015 , PSO has incurred costs of $162 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million , will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of September 30, 2015 , the net book value of Northeastern Plant, Unit 4 was $94 million , before cost of removal, including materials and supplies inventory and CWIP. In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million , based upon returns on common equity ranging from 8.75% to 9.3% , and increases to depreciation expense ranging from $23 million to $46 million . Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC are scheduled for December 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. I&M Rate Matters Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million . In April 2015, I&M filed a notice with the IURC to exclude $117 million related to certain projects. In September 2015, the IURC granted I&M's motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals. |
Southwestern Electric Power Co [Member] | |
Rate Matters | RATE MATTERS As discussed in the 2014 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2014 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2015 and updates the 2014 Annual Report. Regulatory Assets Pending Final Regulatory Approval APCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 8,592 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 32,128 — Peak Demand Reduction/Energy Efficiency – Virginia 11,650 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Deferred Permit Fees Related to Retired Plants – West Virginia 617 — Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory – West Virginia — 3,421 Expanded Net Energy Charge – Construction Surcharge – West Virginia — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval — 168 Total Regulatory Assets Pending Final Regulatory Approval $ 54,937 $ 125,748 I&M September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,652 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,955 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 3,445 1,222 Rockport Dry Sorbent Injection System 1,865 148 Storm Related Costs – Indiana — 1,074 Other Regulatory Assets Pending Final Regulatory Approval 11 712 Total Regulatory Assets Pending Final Regulatory Approval $ 56,904 $ 13,649 OPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Total Regulatory Assets Pending Final Regulatory Approval $ 10,483 $ 10,483 PSO September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project $ 3,031 $ 2,287 Asset Retirement Obligation 1,516 1,144 Rate Case Expenses — 8,126 Other Regulatory Assets Pending Final Regulatory Approval 695 558 Total Regulatory Assets Pending Final Regulatory Approval $ 5,242 $ 12,115 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters Ohio Electric Security Plan Filings 2009 – 2011 ESP The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. In September 2015, the Supreme Court of Ohio denied the IEU's request for reconsideration and in October 2015 this matter was remanded back to the PUCO for reinstatement of the WACC rate. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio, which has scheduled oral arguments for the fourth quarter of 2015. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In April 2015, the PUCO issued an order that approved, with modifications, OPCo's July 2014 application to collect the unrecovered portion of the deferred capacity costs. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of September 30, 2015 , OPCo's net deferred capacity costs balance of $392 million , including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. Through September 30, 2015 , OPCo has collected $183 million in deferred capacity costs, and related carrying charges. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. June 2015 - May 2018 ESP Including PPA Application In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, the PUCO issued an order on rehearing that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In July 2015, the PUCO granted OPCo's and various intervenors' requests for rehearing related to the May 2015 order. In July 2015, intervenors filed appeals with the Supreme Court of Ohio that included opposition to the authorization of a PPA rider and the modifications to a transmission rider. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) included the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. A hearing at the PUCO related to the PPA commenced in September 2015. In October 2015, the PUCO staff submitted testimony that opposed the PPA application as currently proposed but concluded that, with changes, a PPA could be in the public interest. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo submitted its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation and transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo’s generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of September 30, 2015 , is recorded in Regulatory Assets on the condensed balance sheet. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement was held in May 2014. In addition, in the 2009 - 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of September 30, 2015 , the net book value of Welsh Plant, Unit 2 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase was approximately $52 million . In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC review base rates in 2014 and 2015 and that SWEPCo recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million , primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2014 Louisiana Formula Rate Filing In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase, which was effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million . This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchased power agreement attributable to Louisiana customers. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant, Units 1 and 3 – Environmental Projects To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million , excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2024 for Welsh Plant, Units 1 and 3 will cost approximately $700 million , excluding AFUDC. As of September 30, 2015 , SWEPCo has incurred costs of $303 million , including AFUDC, and has remaining contractual construction obligations of $62 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of September 30, 2015 , the net book value of Welsh Plant, Units 1 and 3 was $529 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. APCo Rate Matters 2014 West Virginia Base Rate Case In May 2015, the WVPSC issued an order on APCo's base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $85 million based upon a 9.75% return on common equity. The order included a delayed billing of $22 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $22 million delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $38 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $77 million in previously recorded regulatory assets, which will predominantly be recovered over five years. 2015 Virginia Regulatory Asset Proceeding In January 2015, the Virginia SCC initiated a proceeding to address the proper treatment of APCo’s authorized regulatory assets. In February and March 2015, briefs related to this proceeding were filed by various parties. As of September 30, 2015 , APCo’s authorized regulatory assets under review in this proceeding were $11 million . If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. New Virginia Legislation Affecting Biennial Reviews In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. PSO Rate Matters 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 of Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on common equity of 10.5% to be effective in January 2016, except for the $44 million for environmental investments, which is effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of September 30, 2015 , PSO has incurred costs of $162 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that the incremental replacement capacity and energy costs, including the first year effects of new PPAs, estimated to be $35 million , will be incurred related to the environmental compliance plan due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of September 30, 2015 , the net book value of Northeastern Plant, Unit 4 was $94 million , before cost of removal, including materials and supplies inventory and CWIP. In October 2015, testimony was filed by OCC staff and intervenors with recommendations that included increases to base rates and/or the proposed environmental rider ranging from $10 million to $31 million , based upon returns on common equity ranging from 8.75% to 9.3% , and increases to depreciation expense ranging from $23 million to $46 million . Additionally, recommendations by certain intervenors included (a) no recovery of PSO’s investment in Northeastern Plant, Unit 3 environmental controls, (b) no recovery of the plant balances at the time the units are retired in 2016 and 2026, (c) denial of returns on the book values after the retirement dates, or to be set at only the cost of debt, and (d) the disallowance of the capacity costs associated with the PPAs. Additionally, certain intervenors did not support an increase in depreciation expense for the Northeastern Plant, Units 3 and 4 to permit cost recovery by Unit 3’s 2026 retirement date as the proposals called for no change in existing cost recovery by 2040. Hearings at the OCC are scheduled for December 2015. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. I&M Rate Matters Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies, which are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan for eligible transmission, distribution and storage system improvements totaling $787 million . In April 2015, I&M filed a notice with the IURC to exclude $117 million related to certain projects. In September 2015, the IURC granted I&M's motion to withdraw its application for reconsideration and/or rehearing and I&M withdrew its appeal with the Indiana Court of Appeals. |
Commitments, Guarantees and Con
Commitments, Guarantees and Contingencies | 9 Months Ended |
Sep. 30, 2015 | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES We are subject to certain claims and legal actions arising in our ordinary course of business. In addition, our business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against us cannot be predicted. We accrue contingent liabilities only when we conclude that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When we determine that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, we disclose such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent our maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on our financial statements. The Commitments, Guarantees and Contingencies note within our 2014 Annual Report should be read in conjunction with this report. GUARANTEES We record liabilities for guarantees in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit We enter into standby letters of credit with third parties. As Parent, we issue all of these letters of credit in our ordinary course of business on behalf of our subsidiaries. These letters of credit cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. We have two revolving credit facilities totaling $3.5 billion , under which we may issue up to $1.2 billion as letters of credit. As of September 30, 2015 , the maximum future payments for letters of credit issued under the revolving credit facilities were $33 million with maturities ranging from December 2015 to November 2016. We issue letters of credit under two uncommitted facilities totaling $150 million . As of September 30, 2015 , the maximum future payments for letters of credit issued under the uncommitted facilities were $122 million with maturities ranging from October 2015 to September 2016. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility. We have $477 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $483 million . The letters of credit have maturities ranging from March 2016 to July 2017. Guarantees of Third-Party Obligations SWEPCo As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2015 , SWEPCo has collected $65 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $49 million is recorded in Asset Retirement Obligations on our condensed balance sheets. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Indemnifications and Other Guarantees Contracts We enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. As of September 30, 2015 , there were no material liabilities recorded for any indemnifications. Master Lease Agreements We lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2015 , the maximum potential loss for these lease agreements was $35 million assuming the fair value of the equipment is zero at the end of the lease term. Railcar Lease In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2015 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% under the current five year lease term to 77% at the end of the 20 -year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, we believe that the fair value would produce a sufficient sales price to avoid any loss. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, our generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. We currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of September 30, 2015, I&M's accrual for all of these sites is approximately $8 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. We cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. We have a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Rockport Plant Litigation In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted our motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. Plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. We will continue to defend against the remaining claims. We are unable to determine a range of potential losses that are reasonably possible of occurring. Natural Gas Markets Lawsuits In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) is among the companies named as defendants in some of these cases. We settled, received summary judgment or were dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court's dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court's orders in these cases. The appellate court reversed the district court's holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases. Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. AEP also subsequently filed a separate petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants' previously filed petition for further review with the U.S. Supreme Court on the preemption issue. Oral argument occurred in January 2015. In April 2015, the U.S. Supreme Court affirmed the judgment of the U.S. Court of Appeals for the Ninth Circuit on the preemption issue, holding that the plaintiffs' state antitrust claims were not preempted by the Natural Gas Act. The U.S. Supreme Court denied AEP's petition for review of the personal jurisdiction issue shortly thereafter. The cases have been remanded to the district court for further proceedings. We will continue to defend the cases. We believe the provision we have is adequate. We are unable to determine the amount of potential additional losses that are reasonably possible of occurring. Wage and Hours Lawsuit In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. We will continue to defend the case. We do not believe a loss is probable. If there is an unfavorable outcome contrary to our expectations, we estimate possible losses of up to $30 million . National Do Not Call Registry Lawsuit In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. As a result of a mediation held in October 2014, the parties reached an agreement in principle, subject to final documentation and preliminary and final court approval. In April 2015, we filed a motion with the court for preliminary approval of the settlement. In June 2015, the court granted preliminary approval of the settlement. In September 2015, the court granted final approval of the settlement, reserving decision on the appropriate fee for plaintiff's counsel. Gavin Landfill Litigation In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, we filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied our motion. We appealed that decision to the West Virginia Supreme Court. We will continue to defend against the claims. We are unable to determine a range of potential losses that are reasonably possible of occurring. |
Appalachian Power Co [Member] | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. Contingent liabilities are accrued only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When determined that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, such contingencies and the possible loss or range of loss are disclosed if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2014 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit – Affecting APCo, I&M and OPCo Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , under which up to $1.2 billion may be issued as letters of credit. As of September 30, 2015 , the maximum future payment for letters of credit issued under the revolving credit facilities was as follows: Company Amount Maturity (in thousands) I&M $ 35 March 2016 AEP issues letters of credit under two uncommitted facilities totaling $150 million . An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. As of September 30, 2015 , the maximum future payment for letters of credit issued under the uncommitted facilities was as follows: Company Amount Maturity (in thousands) OPCo $ 4,200 September 2016 The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 Guarantees of Third-Party Obligations – Affecting SWEPCo As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2015 , SWEPCo has collected $65 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $49 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo Contracts The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of September 30, 2015 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2015 , the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows: Company Maximum Potential Loss (in thousands) APCo $ 5,396 I&M 3,448 OPCo 6,075 PSO 2,785 SWEPCo 3,086 Railcar Lease In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2015 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% under the current five year lease term to 77% at the end of the 20 -year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five -year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrant Subsidiaries currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of September 30, 2015, I&M's accrual for all of these sites is approximately $8 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES – AFFECTING I&M I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Rockport Plant Litigation – Affecting I&M In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. Plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. Management will continue to defend against the remaining claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. Wage and Hours Lawsuit – Affecting PSO In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million . Gavin Landfill Litigation – Affecting OPCo In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management appealed that decision to the West Virginia Supreme Court. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. |
Indiana Michigan Power Co [Member] | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. Contingent liabilities are accrued only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When determined that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, such contingencies and the possible loss or range of loss are disclosed if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2014 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit – Affecting APCo, I&M and OPCo Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , under which up to $1.2 billion may be issued as letters of credit. As of September 30, 2015 , the maximum future payment for letters of credit issued under the revolving credit facilities was as follows: Company Amount Maturity (in thousands) I&M $ 35 March 2016 AEP issues letters of credit under two uncommitted facilities totaling $150 million . An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. As of September 30, 2015 , the maximum future payment for letters of credit issued under the uncommitted facilities was as follows: Company Amount Maturity (in thousands) OPCo $ 4,200 September 2016 The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 Guarantees of Third-Party Obligations – Affecting SWEPCo As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2015 , SWEPCo has collected $65 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $49 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo Contracts The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of September 30, 2015 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2015 , the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows: Company Maximum Potential Loss (in thousands) APCo $ 5,396 I&M 3,448 OPCo 6,075 PSO 2,785 SWEPCo 3,086 Railcar Lease In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2015 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% under the current five year lease term to 77% at the end of the 20 -year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five -year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrant Subsidiaries currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of September 30, 2015, I&M's accrual for all of these sites is approximately $8 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES – AFFECTING I&M I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Rockport Plant Litigation – Affecting I&M In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. Plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. Management will continue to defend against the remaining claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. Wage and Hours Lawsuit – Affecting PSO In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million . Gavin Landfill Litigation – Affecting OPCo In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management appealed that decision to the West Virginia Supreme Court. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. |
Ohio Power Co [Member] | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. Contingent liabilities are accrued only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When determined that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, such contingencies and the possible loss or range of loss are disclosed if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2014 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit – Affecting APCo, I&M and OPCo Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , under which up to $1.2 billion may be issued as letters of credit. As of September 30, 2015 , the maximum future payment for letters of credit issued under the revolving credit facilities was as follows: Company Amount Maturity (in thousands) I&M $ 35 March 2016 AEP issues letters of credit under two uncommitted facilities totaling $150 million . An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. As of September 30, 2015 , the maximum future payment for letters of credit issued under the uncommitted facilities was as follows: Company Amount Maturity (in thousands) OPCo $ 4,200 September 2016 The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 Guarantees of Third-Party Obligations – Affecting SWEPCo As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2015 , SWEPCo has collected $65 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $49 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo Contracts The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of September 30, 2015 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2015 , the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows: Company Maximum Potential Loss (in thousands) APCo $ 5,396 I&M 3,448 OPCo 6,075 PSO 2,785 SWEPCo 3,086 Railcar Lease In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2015 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% under the current five year lease term to 77% at the end of the 20 -year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five -year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrant Subsidiaries currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of September 30, 2015, I&M's accrual for all of these sites is approximately $8 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES – AFFECTING I&M I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Rockport Plant Litigation – Affecting I&M In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. Plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. Management will continue to defend against the remaining claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. Wage and Hours Lawsuit – Affecting PSO In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million . Gavin Landfill Litigation – Affecting OPCo In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management appealed that decision to the West Virginia Supreme Court. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. |
Public Service Co Of Oklahoma [Member] | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. Contingent liabilities are accrued only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When determined that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, such contingencies and the possible loss or range of loss are disclosed if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2014 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit – Affecting APCo, I&M and OPCo Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , under which up to $1.2 billion may be issued as letters of credit. As of September 30, 2015 , the maximum future payment for letters of credit issued under the revolving credit facilities was as follows: Company Amount Maturity (in thousands) I&M $ 35 March 2016 AEP issues letters of credit under two uncommitted facilities totaling $150 million . An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. As of September 30, 2015 , the maximum future payment for letters of credit issued under the uncommitted facilities was as follows: Company Amount Maturity (in thousands) OPCo $ 4,200 September 2016 The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 Guarantees of Third-Party Obligations – Affecting SWEPCo As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2015 , SWEPCo has collected $65 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $49 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo Contracts The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of September 30, 2015 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2015 , the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows: Company Maximum Potential Loss (in thousands) APCo $ 5,396 I&M 3,448 OPCo 6,075 PSO 2,785 SWEPCo 3,086 Railcar Lease In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2015 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% under the current five year lease term to 77% at the end of the 20 -year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five -year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrant Subsidiaries currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of September 30, 2015, I&M's accrual for all of these sites is approximately $8 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES – AFFECTING I&M I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Rockport Plant Litigation – Affecting I&M In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. Plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. Management will continue to defend against the remaining claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. Wage and Hours Lawsuit – Affecting PSO In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million . Gavin Landfill Litigation – Affecting OPCo In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management appealed that decision to the West Virginia Supreme Court. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. |
Southwestern Electric Power Co [Member] | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. Contingent liabilities are accrued only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When determined that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, such contingencies and the possible loss or range of loss are disclosed if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2014 Annual Report should be read in conjunction with this report. GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit – Affecting APCo, I&M and OPCo Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion , under which up to $1.2 billion may be issued as letters of credit. As of September 30, 2015 , the maximum future payment for letters of credit issued under the revolving credit facilities was as follows: Company Amount Maturity (in thousands) I&M $ 35 March 2016 AEP issues letters of credit under two uncommitted facilities totaling $150 million . An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. As of September 30, 2015 , the maximum future payment for letters of credit issued under the uncommitted facilities was as follows: Company Amount Maturity (in thousands) OPCo $ 4,200 September 2016 The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 Guarantees of Third-Party Obligations – Affecting SWEPCo As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million . Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2015 , SWEPCo has collected $65 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $49 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed balance sheets. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo Contracts The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of September 30, 2015 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity. Master Lease Agreements The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of September 30, 2015 , the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows: Company Maximum Potential Loss (in thousands) APCo $ 5,396 I&M 3,448 OPCo 6,075 PSO 2,785 SWEPCo 3,086 Railcar Lease In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M ( 390 railcars) and SWEPCo ( 458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2015 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% under the current five year lease term to 77% at the end of the 20 -year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five -year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrant Subsidiaries currently incur costs to dispose of these substances safely. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of September 30, 2015, I&M's accrual for all of these sites is approximately $8 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES – AFFECTING I&M I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Rockport Plant Litigation – Affecting I&M In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. Plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. Management will continue to defend against the remaining claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. Wage and Hours Lawsuit – Affecting PSO In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. In March 2014, the federal court granted plaintiffs’ motion to conditionally certify the action as a class action. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. Management will continue to defend the case. Management does not believe a loss is probable. If there is an unfavorable outcome contrary to expectations, management estimates possible losses of up to $30 million . Gavin Landfill Litigation – Affecting OPCo In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Management appealed that decision to the West Virginia Supreme Court. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. |
Disposition, Assets and Liabili
Disposition, Assets and Liabilities Held for Sale and Discontinued Operations | 9 Months Ended |
Sep. 30, 2015 | |
Disposition, Assets and Liabilities Held for Sale and Discontinued Operations | DISPOSITION, ASSETS AND LIABILITIES HELD FOR SALE AND DISCONTINUED OPERATIONS DISPOSITION 2015 Muskingum River Plant (Generation & Marketing Segment) In August 2015, AGR sold its retired Muskingum River Plant site including its associated asset retirement obligations to a nonaffiliated party. AGR paid $48 million and the nonaffiliated party took ownership of the Muskingum River Plant site assets and assumed responsibility for environmental liabilities and AROs, including ash pond closure, asbestos abatement and decommissioning and demolition. As a result of the sale, a net gain of $32 million was recognized and recorded in Other Operation on the condensed consolidated statements of income. The cash paid was recorded in Operating Activities on the condensed consolidated statements of cash flows. ASSETS AND LIABILITIES HELD FOR SALE AEPRO (AEP River Operations Segment) During the third quarter of 2015, we evaluated bids from prospective buyers, selected a buyer and received approval from AEP's Board of Directors to proceed with the sale to the nonaffiliated party. In October 2015, we signed an agreement to sell our commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale of AEPRO is subject to regulatory approval including federal clearance pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Upon close of the sale, the nonaffiliated party will acquire AEPRO by purchasing all of the common stock of AEP Resources, Inc., the parent company of AEPRO. The nonaffiliated party will assume certain assets and liabilities of AEPRO, excluding the equity method investment in IMT, pension and benefit assets and liabilities and debt obligations. We will retain ownership of our captive barge fleet that delivers coal to the company's regulated coal-fueled power plant units owned or leased by AEGCo, APCo, I&M, KPCo and WPCo. We signed a contract with the nonaffiliated party to dispatch and schedule our captive barge fleet for the company's regulated coal-fueled power plant units. We also contracted with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2016. The sale is expected to close in the fourth quarter of 2015. Upon evaluation, management concluded that the AEPRO business met the classification as held for sale in the third quarter of 2015. Accordingly, AEPRO's assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on our condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014 and as shown in the following table: September 30, 2015 December 31, 2014 Assets: (in millions) Accounts Receivable $ 55 $ 91 Property, Plant and Equipment – Net 506 482 Other Classes of Assets That Are Not Major 47 52 Total Assets Classified as Held for Sale on the Condensed Consolidated Balance Sheets $ 608 $ 625 Liabilities: Long-term Debt $ 81 $ 83 Obligations Under Capital Leases 228 189 Other Classes of Liabilities That Are Not Major 165 163 Total Liabilities Classified as Held for Sale on the Condensed Consolidated Balance Sheets $ 474 $ 435 DISCONTINUED OPERATIONS Management periodically assesses the overall AEP business model and makes decisions regarding our continued support and funding of our various businesses and operations. When it is determined that we will seek to exit a particular business or activity and we have met the accounting requirements for reclassification, we will reclassify the operations of those businesses or operations as discontinued operations. The assets and liabilities of these discontinued operations are classified as Assets Held for Sale and Liabilities Held for Sale until the time they are sold. In the third quarter of 2015, AEPRO was determined to be discontinued operations and has been classified as such for third quarter 2015 reporting. Results of operations of AEPRO have been classified as discontinued operations in our condensed consolidated statements of income for the three and nine months ended September 30, 2015 and 2014 as shown in the following table: Three Months Ended Nine Months Ended 2015 2014 2015 2014 (in millions) Other Revenues $ 129 $ 141 $ 372 $ 435 Other Operation Expense 96 102 273 342 Maintenance Expense 4 8 20 24 Depreciation and Amortization Expense 9 8 27 23 Other Expense 8 7 24 22 Total Expenses 117 125 344 411 Pretax Income of Discontinued Operations 12 16 28 24 Income Tax Expense 4 5 10 8 Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income $ 8 $ 11 $ 18 $ 16 |
Benefit Plans
Benefit Plans | 9 Months Ended |
Sep. 30, 2015 | |
Benefit Plans | BENEFIT PLANS We sponsor a qualified pension plan and two unfunded nonqualified pension plans. Substantially all of our employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. We sponsor OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of our net periodic benefit cost (credit) for the plans for the three and nine months ended September 30, 2015 and 2014 : Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in millions) Service Cost $ 23 $ 18 $ 3 $ 4 Interest Cost 51 55 15 16 Expected Return on Plan Assets (69 ) (65 ) (28 ) (28 ) Amortization of Prior Service Cost (Credit) 1 1 (18 ) (18 ) Amortization of Net Actuarial Loss 27 31 5 6 Net Periodic Benefit Cost (Credit) $ 33 $ 40 $ (23 ) $ (20 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in millions) Service Cost $ 70 $ 54 $ 9 $ 11 Interest Cost 154 166 43 50 Expected Return on Plan Assets (206 ) (196 ) (83 ) (84 ) Amortization of Prior Service Cost (Credit) 2 2 (52 ) (52 ) Amortization of Net Actuarial Loss 80 93 14 17 Net Periodic Benefit Cost (Credit) $ 100 $ 119 $ (69 ) $ (58 ) |
Appalachian Power Co [Member] | |
Benefit Plans | BENEFIT PLANS The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2015 and 2014 : APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,175 $ 1,759 $ 286 $ 362 Interest Cost 6,679 7,406 2,584 3,197 Expected Return on Plan Assets (8,745 ) (8,482 ) (4,529 ) (4,634 ) Amortization of Prior Service Cost (Credit) 45 49 (2,513 ) (2,512 ) Amortization of Net Actuarial Loss 3,474 4,149 900 1,145 Net Periodic Benefit Cost (Credit) $ 3,628 $ 4,881 $ (3,272 ) $ (2,442 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,525 $ 5,277 $ 857 $ 1,086 Interest Cost 20,037 22,218 7,753 9,591 Expected Return on Plan Assets (26,236 ) (25,445 ) (13,587 ) (13,900 ) Amortization of Prior Service Cost (Credit) 135 148 (7,538 ) (7,537 ) Amortization of Net Actuarial Loss 10,421 12,445 2,699 3,436 Net Periodic Benefit Cost (Credit) $ 10,882 $ 14,643 $ (9,816 ) $ (7,324 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,217 $ 2,517 $ 406 $ 486 Interest Cost 6,114 6,573 1,592 1,909 Expected Return on Plan Assets (8,115 ) (7,749 ) (3,304 ) (3,363 ) Amortization of Prior Service Cost (Credit) 45 49 (2,355 ) (2,355 ) Amortization of Net Actuarial Loss 3,145 3,647 506 592 Net Periodic Benefit Cost (Credit) $ 4,406 $ 5,037 $ (3,155 ) $ (2,731 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 9,651 $ 7,551 $ 1,219 $ 1,460 Interest Cost 18,344 19,720 4,776 5,728 Expected Return on Plan Assets (24,347 ) (23,245 ) (9,912 ) (10,090 ) Amortization of Prior Service Cost (Credit) 136 146 (7,066 ) (7,066 ) Amortization of Net Actuarial Loss 9,434 10,939 1,519 1,776 Net Periodic Benefit Cost (Credit) $ 13,218 $ 15,111 $ (9,464 ) $ (8,192 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,671 $ 1,285 $ 216 $ 256 Interest Cost 5,071 5,527 1,615 1,900 Expected Return on Plan Assets (6,878 ) (6,607 ) (3,376 ) (3,379 ) Amortization of Prior Service Cost (Credit) 35 40 (1,731 ) (1,731 ) Amortization of Net Actuarial Loss 2,644 3,105 517 595 Net Periodic Benefit Cost (Credit) $ 2,543 $ 3,350 $ (2,759 ) $ (2,359 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 5,015 $ 3,855 $ 647 $ 769 Interest Cost 15,211 16,579 4,845 5,701 Expected Return on Plan Assets (20,634 ) (19,820 ) (10,130 ) (10,139 ) Amortization of Prior Service Cost (Credit) 105 118 (5,192 ) (5,192 ) Amortization of Net Actuarial Loss 7,932 9,316 1,552 1,785 Net Periodic Benefit Cost (Credit) $ 7,629 $ 10,048 $ (8,278 ) $ (7,076 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,598 $ 1,301 $ 170 $ 209 Interest Cost 2,731 3,015 759 893 Expected Return on Plan Assets (3,786 ) (3,651 ) (1,578 ) (1,575 ) Amortization of Prior Service Cost (Credit) 63 74 (1,072 ) (1,072 ) Amortization of Net Actuarial Loss 1,418 1,689 242 278 Net Periodic Benefit Cost (Credit) $ 2,024 $ 2,428 $ (1,479 ) $ (1,267 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,796 $ 3,905 $ 509 $ 629 Interest Cost 8,194 9,043 2,277 2,680 Expected Return on Plan Assets (11,358 ) (10,953 ) (4,732 ) (4,725 ) Amortization of Prior Service Cost (Credit) 189 222 (3,217 ) (3,217 ) Amortization of Net Actuarial Loss 4,252 5,065 725 832 Net Periodic Benefit Cost (Credit) $ 6,073 $ 7,282 $ (4,438 ) $ (3,801 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,081 $ 1,655 $ 211 $ 253 Interest Cost 2,932 3,163 837 998 Expected Return on Plan Assets (4,008 ) (3,857 ) (1,735 ) (1,754 ) Amortization of Prior Service Cost (Credit) 78 87 (1,289 ) (1,289 ) Amortization of Net Actuarial Loss 1,506 1,762 266 309 Net Periodic Benefit Cost (Credit) $ 2,589 $ 2,810 $ (1,710 ) $ (1,483 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,244 $ 4,964 $ 632 $ 759 Interest Cost 8,796 9,488 2,512 2,994 Expected Return on Plan Assets (12,024 ) (11,571 ) (5,206 ) (5,262 ) Amortization of Prior Service Cost (Credit) 232 262 (3,867 ) (3,867 ) Amortization of Net Actuarial Loss 4,520 5,285 798 926 Net Periodic Benefit Cost (Credit) $ 7,768 $ 8,428 $ (5,131 ) $ (4,450 ) |
Indiana Michigan Power Co [Member] | |
Benefit Plans | BENEFIT PLANS The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2015 and 2014 : APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,175 $ 1,759 $ 286 $ 362 Interest Cost 6,679 7,406 2,584 3,197 Expected Return on Plan Assets (8,745 ) (8,482 ) (4,529 ) (4,634 ) Amortization of Prior Service Cost (Credit) 45 49 (2,513 ) (2,512 ) Amortization of Net Actuarial Loss 3,474 4,149 900 1,145 Net Periodic Benefit Cost (Credit) $ 3,628 $ 4,881 $ (3,272 ) $ (2,442 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,525 $ 5,277 $ 857 $ 1,086 Interest Cost 20,037 22,218 7,753 9,591 Expected Return on Plan Assets (26,236 ) (25,445 ) (13,587 ) (13,900 ) Amortization of Prior Service Cost (Credit) 135 148 (7,538 ) (7,537 ) Amortization of Net Actuarial Loss 10,421 12,445 2,699 3,436 Net Periodic Benefit Cost (Credit) $ 10,882 $ 14,643 $ (9,816 ) $ (7,324 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,217 $ 2,517 $ 406 $ 486 Interest Cost 6,114 6,573 1,592 1,909 Expected Return on Plan Assets (8,115 ) (7,749 ) (3,304 ) (3,363 ) Amortization of Prior Service Cost (Credit) 45 49 (2,355 ) (2,355 ) Amortization of Net Actuarial Loss 3,145 3,647 506 592 Net Periodic Benefit Cost (Credit) $ 4,406 $ 5,037 $ (3,155 ) $ (2,731 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 9,651 $ 7,551 $ 1,219 $ 1,460 Interest Cost 18,344 19,720 4,776 5,728 Expected Return on Plan Assets (24,347 ) (23,245 ) (9,912 ) (10,090 ) Amortization of Prior Service Cost (Credit) 136 146 (7,066 ) (7,066 ) Amortization of Net Actuarial Loss 9,434 10,939 1,519 1,776 Net Periodic Benefit Cost (Credit) $ 13,218 $ 15,111 $ (9,464 ) $ (8,192 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,671 $ 1,285 $ 216 $ 256 Interest Cost 5,071 5,527 1,615 1,900 Expected Return on Plan Assets (6,878 ) (6,607 ) (3,376 ) (3,379 ) Amortization of Prior Service Cost (Credit) 35 40 (1,731 ) (1,731 ) Amortization of Net Actuarial Loss 2,644 3,105 517 595 Net Periodic Benefit Cost (Credit) $ 2,543 $ 3,350 $ (2,759 ) $ (2,359 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 5,015 $ 3,855 $ 647 $ 769 Interest Cost 15,211 16,579 4,845 5,701 Expected Return on Plan Assets (20,634 ) (19,820 ) (10,130 ) (10,139 ) Amortization of Prior Service Cost (Credit) 105 118 (5,192 ) (5,192 ) Amortization of Net Actuarial Loss 7,932 9,316 1,552 1,785 Net Periodic Benefit Cost (Credit) $ 7,629 $ 10,048 $ (8,278 ) $ (7,076 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,598 $ 1,301 $ 170 $ 209 Interest Cost 2,731 3,015 759 893 Expected Return on Plan Assets (3,786 ) (3,651 ) (1,578 ) (1,575 ) Amortization of Prior Service Cost (Credit) 63 74 (1,072 ) (1,072 ) Amortization of Net Actuarial Loss 1,418 1,689 242 278 Net Periodic Benefit Cost (Credit) $ 2,024 $ 2,428 $ (1,479 ) $ (1,267 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,796 $ 3,905 $ 509 $ 629 Interest Cost 8,194 9,043 2,277 2,680 Expected Return on Plan Assets (11,358 ) (10,953 ) (4,732 ) (4,725 ) Amortization of Prior Service Cost (Credit) 189 222 (3,217 ) (3,217 ) Amortization of Net Actuarial Loss 4,252 5,065 725 832 Net Periodic Benefit Cost (Credit) $ 6,073 $ 7,282 $ (4,438 ) $ (3,801 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,081 $ 1,655 $ 211 $ 253 Interest Cost 2,932 3,163 837 998 Expected Return on Plan Assets (4,008 ) (3,857 ) (1,735 ) (1,754 ) Amortization of Prior Service Cost (Credit) 78 87 (1,289 ) (1,289 ) Amortization of Net Actuarial Loss 1,506 1,762 266 309 Net Periodic Benefit Cost (Credit) $ 2,589 $ 2,810 $ (1,710 ) $ (1,483 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,244 $ 4,964 $ 632 $ 759 Interest Cost 8,796 9,488 2,512 2,994 Expected Return on Plan Assets (12,024 ) (11,571 ) (5,206 ) (5,262 ) Amortization of Prior Service Cost (Credit) 232 262 (3,867 ) (3,867 ) Amortization of Net Actuarial Loss 4,520 5,285 798 926 Net Periodic Benefit Cost (Credit) $ 7,768 $ 8,428 $ (5,131 ) $ (4,450 ) |
Ohio Power Co [Member] | |
Benefit Plans | BENEFIT PLANS The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2015 and 2014 : APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,175 $ 1,759 $ 286 $ 362 Interest Cost 6,679 7,406 2,584 3,197 Expected Return on Plan Assets (8,745 ) (8,482 ) (4,529 ) (4,634 ) Amortization of Prior Service Cost (Credit) 45 49 (2,513 ) (2,512 ) Amortization of Net Actuarial Loss 3,474 4,149 900 1,145 Net Periodic Benefit Cost (Credit) $ 3,628 $ 4,881 $ (3,272 ) $ (2,442 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,525 $ 5,277 $ 857 $ 1,086 Interest Cost 20,037 22,218 7,753 9,591 Expected Return on Plan Assets (26,236 ) (25,445 ) (13,587 ) (13,900 ) Amortization of Prior Service Cost (Credit) 135 148 (7,538 ) (7,537 ) Amortization of Net Actuarial Loss 10,421 12,445 2,699 3,436 Net Periodic Benefit Cost (Credit) $ 10,882 $ 14,643 $ (9,816 ) $ (7,324 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,217 $ 2,517 $ 406 $ 486 Interest Cost 6,114 6,573 1,592 1,909 Expected Return on Plan Assets (8,115 ) (7,749 ) (3,304 ) (3,363 ) Amortization of Prior Service Cost (Credit) 45 49 (2,355 ) (2,355 ) Amortization of Net Actuarial Loss 3,145 3,647 506 592 Net Periodic Benefit Cost (Credit) $ 4,406 $ 5,037 $ (3,155 ) $ (2,731 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 9,651 $ 7,551 $ 1,219 $ 1,460 Interest Cost 18,344 19,720 4,776 5,728 Expected Return on Plan Assets (24,347 ) (23,245 ) (9,912 ) (10,090 ) Amortization of Prior Service Cost (Credit) 136 146 (7,066 ) (7,066 ) Amortization of Net Actuarial Loss 9,434 10,939 1,519 1,776 Net Periodic Benefit Cost (Credit) $ 13,218 $ 15,111 $ (9,464 ) $ (8,192 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,671 $ 1,285 $ 216 $ 256 Interest Cost 5,071 5,527 1,615 1,900 Expected Return on Plan Assets (6,878 ) (6,607 ) (3,376 ) (3,379 ) Amortization of Prior Service Cost (Credit) 35 40 (1,731 ) (1,731 ) Amortization of Net Actuarial Loss 2,644 3,105 517 595 Net Periodic Benefit Cost (Credit) $ 2,543 $ 3,350 $ (2,759 ) $ (2,359 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 5,015 $ 3,855 $ 647 $ 769 Interest Cost 15,211 16,579 4,845 5,701 Expected Return on Plan Assets (20,634 ) (19,820 ) (10,130 ) (10,139 ) Amortization of Prior Service Cost (Credit) 105 118 (5,192 ) (5,192 ) Amortization of Net Actuarial Loss 7,932 9,316 1,552 1,785 Net Periodic Benefit Cost (Credit) $ 7,629 $ 10,048 $ (8,278 ) $ (7,076 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,598 $ 1,301 $ 170 $ 209 Interest Cost 2,731 3,015 759 893 Expected Return on Plan Assets (3,786 ) (3,651 ) (1,578 ) (1,575 ) Amortization of Prior Service Cost (Credit) 63 74 (1,072 ) (1,072 ) Amortization of Net Actuarial Loss 1,418 1,689 242 278 Net Periodic Benefit Cost (Credit) $ 2,024 $ 2,428 $ (1,479 ) $ (1,267 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,796 $ 3,905 $ 509 $ 629 Interest Cost 8,194 9,043 2,277 2,680 Expected Return on Plan Assets (11,358 ) (10,953 ) (4,732 ) (4,725 ) Amortization of Prior Service Cost (Credit) 189 222 (3,217 ) (3,217 ) Amortization of Net Actuarial Loss 4,252 5,065 725 832 Net Periodic Benefit Cost (Credit) $ 6,073 $ 7,282 $ (4,438 ) $ (3,801 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,081 $ 1,655 $ 211 $ 253 Interest Cost 2,932 3,163 837 998 Expected Return on Plan Assets (4,008 ) (3,857 ) (1,735 ) (1,754 ) Amortization of Prior Service Cost (Credit) 78 87 (1,289 ) (1,289 ) Amortization of Net Actuarial Loss 1,506 1,762 266 309 Net Periodic Benefit Cost (Credit) $ 2,589 $ 2,810 $ (1,710 ) $ (1,483 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,244 $ 4,964 $ 632 $ 759 Interest Cost 8,796 9,488 2,512 2,994 Expected Return on Plan Assets (12,024 ) (11,571 ) (5,206 ) (5,262 ) Amortization of Prior Service Cost (Credit) 232 262 (3,867 ) (3,867 ) Amortization of Net Actuarial Loss 4,520 5,285 798 926 Net Periodic Benefit Cost (Credit) $ 7,768 $ 8,428 $ (5,131 ) $ (4,450 ) |
Public Service Co Of Oklahoma [Member] | |
Benefit Plans | BENEFIT PLANS The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2015 and 2014 : APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,175 $ 1,759 $ 286 $ 362 Interest Cost 6,679 7,406 2,584 3,197 Expected Return on Plan Assets (8,745 ) (8,482 ) (4,529 ) (4,634 ) Amortization of Prior Service Cost (Credit) 45 49 (2,513 ) (2,512 ) Amortization of Net Actuarial Loss 3,474 4,149 900 1,145 Net Periodic Benefit Cost (Credit) $ 3,628 $ 4,881 $ (3,272 ) $ (2,442 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,525 $ 5,277 $ 857 $ 1,086 Interest Cost 20,037 22,218 7,753 9,591 Expected Return on Plan Assets (26,236 ) (25,445 ) (13,587 ) (13,900 ) Amortization of Prior Service Cost (Credit) 135 148 (7,538 ) (7,537 ) Amortization of Net Actuarial Loss 10,421 12,445 2,699 3,436 Net Periodic Benefit Cost (Credit) $ 10,882 $ 14,643 $ (9,816 ) $ (7,324 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,217 $ 2,517 $ 406 $ 486 Interest Cost 6,114 6,573 1,592 1,909 Expected Return on Plan Assets (8,115 ) (7,749 ) (3,304 ) (3,363 ) Amortization of Prior Service Cost (Credit) 45 49 (2,355 ) (2,355 ) Amortization of Net Actuarial Loss 3,145 3,647 506 592 Net Periodic Benefit Cost (Credit) $ 4,406 $ 5,037 $ (3,155 ) $ (2,731 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 9,651 $ 7,551 $ 1,219 $ 1,460 Interest Cost 18,344 19,720 4,776 5,728 Expected Return on Plan Assets (24,347 ) (23,245 ) (9,912 ) (10,090 ) Amortization of Prior Service Cost (Credit) 136 146 (7,066 ) (7,066 ) Amortization of Net Actuarial Loss 9,434 10,939 1,519 1,776 Net Periodic Benefit Cost (Credit) $ 13,218 $ 15,111 $ (9,464 ) $ (8,192 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,671 $ 1,285 $ 216 $ 256 Interest Cost 5,071 5,527 1,615 1,900 Expected Return on Plan Assets (6,878 ) (6,607 ) (3,376 ) (3,379 ) Amortization of Prior Service Cost (Credit) 35 40 (1,731 ) (1,731 ) Amortization of Net Actuarial Loss 2,644 3,105 517 595 Net Periodic Benefit Cost (Credit) $ 2,543 $ 3,350 $ (2,759 ) $ (2,359 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 5,015 $ 3,855 $ 647 $ 769 Interest Cost 15,211 16,579 4,845 5,701 Expected Return on Plan Assets (20,634 ) (19,820 ) (10,130 ) (10,139 ) Amortization of Prior Service Cost (Credit) 105 118 (5,192 ) (5,192 ) Amortization of Net Actuarial Loss 7,932 9,316 1,552 1,785 Net Periodic Benefit Cost (Credit) $ 7,629 $ 10,048 $ (8,278 ) $ (7,076 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,598 $ 1,301 $ 170 $ 209 Interest Cost 2,731 3,015 759 893 Expected Return on Plan Assets (3,786 ) (3,651 ) (1,578 ) (1,575 ) Amortization of Prior Service Cost (Credit) 63 74 (1,072 ) (1,072 ) Amortization of Net Actuarial Loss 1,418 1,689 242 278 Net Periodic Benefit Cost (Credit) $ 2,024 $ 2,428 $ (1,479 ) $ (1,267 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,796 $ 3,905 $ 509 $ 629 Interest Cost 8,194 9,043 2,277 2,680 Expected Return on Plan Assets (11,358 ) (10,953 ) (4,732 ) (4,725 ) Amortization of Prior Service Cost (Credit) 189 222 (3,217 ) (3,217 ) Amortization of Net Actuarial Loss 4,252 5,065 725 832 Net Periodic Benefit Cost (Credit) $ 6,073 $ 7,282 $ (4,438 ) $ (3,801 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,081 $ 1,655 $ 211 $ 253 Interest Cost 2,932 3,163 837 998 Expected Return on Plan Assets (4,008 ) (3,857 ) (1,735 ) (1,754 ) Amortization of Prior Service Cost (Credit) 78 87 (1,289 ) (1,289 ) Amortization of Net Actuarial Loss 1,506 1,762 266 309 Net Periodic Benefit Cost (Credit) $ 2,589 $ 2,810 $ (1,710 ) $ (1,483 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,244 $ 4,964 $ 632 $ 759 Interest Cost 8,796 9,488 2,512 2,994 Expected Return on Plan Assets (12,024 ) (11,571 ) (5,206 ) (5,262 ) Amortization of Prior Service Cost (Credit) 232 262 (3,867 ) (3,867 ) Amortization of Net Actuarial Loss 4,520 5,285 798 926 Net Periodic Benefit Cost (Credit) $ 7,768 $ 8,428 $ (5,131 ) $ (4,450 ) |
Southwestern Electric Power Co [Member] | |
Benefit Plans | BENEFIT PLANS The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2015 and 2014 : APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,175 $ 1,759 $ 286 $ 362 Interest Cost 6,679 7,406 2,584 3,197 Expected Return on Plan Assets (8,745 ) (8,482 ) (4,529 ) (4,634 ) Amortization of Prior Service Cost (Credit) 45 49 (2,513 ) (2,512 ) Amortization of Net Actuarial Loss 3,474 4,149 900 1,145 Net Periodic Benefit Cost (Credit) $ 3,628 $ 4,881 $ (3,272 ) $ (2,442 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,525 $ 5,277 $ 857 $ 1,086 Interest Cost 20,037 22,218 7,753 9,591 Expected Return on Plan Assets (26,236 ) (25,445 ) (13,587 ) (13,900 ) Amortization of Prior Service Cost (Credit) 135 148 (7,538 ) (7,537 ) Amortization of Net Actuarial Loss 10,421 12,445 2,699 3,436 Net Periodic Benefit Cost (Credit) $ 10,882 $ 14,643 $ (9,816 ) $ (7,324 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,217 $ 2,517 $ 406 $ 486 Interest Cost 6,114 6,573 1,592 1,909 Expected Return on Plan Assets (8,115 ) (7,749 ) (3,304 ) (3,363 ) Amortization of Prior Service Cost (Credit) 45 49 (2,355 ) (2,355 ) Amortization of Net Actuarial Loss 3,145 3,647 506 592 Net Periodic Benefit Cost (Credit) $ 4,406 $ 5,037 $ (3,155 ) $ (2,731 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 9,651 $ 7,551 $ 1,219 $ 1,460 Interest Cost 18,344 19,720 4,776 5,728 Expected Return on Plan Assets (24,347 ) (23,245 ) (9,912 ) (10,090 ) Amortization of Prior Service Cost (Credit) 136 146 (7,066 ) (7,066 ) Amortization of Net Actuarial Loss 9,434 10,939 1,519 1,776 Net Periodic Benefit Cost (Credit) $ 13,218 $ 15,111 $ (9,464 ) $ (8,192 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,671 $ 1,285 $ 216 $ 256 Interest Cost 5,071 5,527 1,615 1,900 Expected Return on Plan Assets (6,878 ) (6,607 ) (3,376 ) (3,379 ) Amortization of Prior Service Cost (Credit) 35 40 (1,731 ) (1,731 ) Amortization of Net Actuarial Loss 2,644 3,105 517 595 Net Periodic Benefit Cost (Credit) $ 2,543 $ 3,350 $ (2,759 ) $ (2,359 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 5,015 $ 3,855 $ 647 $ 769 Interest Cost 15,211 16,579 4,845 5,701 Expected Return on Plan Assets (20,634 ) (19,820 ) (10,130 ) (10,139 ) Amortization of Prior Service Cost (Credit) 105 118 (5,192 ) (5,192 ) Amortization of Net Actuarial Loss 7,932 9,316 1,552 1,785 Net Periodic Benefit Cost (Credit) $ 7,629 $ 10,048 $ (8,278 ) $ (7,076 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,598 $ 1,301 $ 170 $ 209 Interest Cost 2,731 3,015 759 893 Expected Return on Plan Assets (3,786 ) (3,651 ) (1,578 ) (1,575 ) Amortization of Prior Service Cost (Credit) 63 74 (1,072 ) (1,072 ) Amortization of Net Actuarial Loss 1,418 1,689 242 278 Net Periodic Benefit Cost (Credit) $ 2,024 $ 2,428 $ (1,479 ) $ (1,267 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,796 $ 3,905 $ 509 $ 629 Interest Cost 8,194 9,043 2,277 2,680 Expected Return on Plan Assets (11,358 ) (10,953 ) (4,732 ) (4,725 ) Amortization of Prior Service Cost (Credit) 189 222 (3,217 ) (3,217 ) Amortization of Net Actuarial Loss 4,252 5,065 725 832 Net Periodic Benefit Cost (Credit) $ 6,073 $ 7,282 $ (4,438 ) $ (3,801 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,081 $ 1,655 $ 211 $ 253 Interest Cost 2,932 3,163 837 998 Expected Return on Plan Assets (4,008 ) (3,857 ) (1,735 ) (1,754 ) Amortization of Prior Service Cost (Credit) 78 87 (1,289 ) (1,289 ) Amortization of Net Actuarial Loss 1,506 1,762 266 309 Net Periodic Benefit Cost (Credit) $ 2,589 $ 2,810 $ (1,710 ) $ (1,483 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,244 $ 4,964 $ 632 $ 759 Interest Cost 8,796 9,488 2,512 2,994 Expected Return on Plan Assets (12,024 ) (11,571 ) (5,206 ) (5,262 ) Amortization of Prior Service Cost (Credit) 232 262 (3,867 ) (3,867 ) Amortization of Net Actuarial Loss 4,520 5,285 798 926 Net Periodic Benefit Cost (Credit) $ 7,768 $ 8,428 $ (5,131 ) $ (4,450 ) |
Business Segments
Business Segments | 9 Months Ended |
Sep. 30, 2015 | |
Business Segments | BUSINESS SEGMENTS Our primary business is the generation, transmission and distribution of electricity. Within our Vertically Integrated Utilities segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. Our reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in our wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Nonregulated generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM and MISO. AEP River Operations • Commercial barging operations that transports liquids, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers. • In October 2015, we signed an agreement to sell AEPRO to a nonaffiliated party. The AEP River Operations segment is comprised entirely of AEPRO. However, we will retain AEPRO's investment in IMT. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. The remainder of our activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present our reportable segment income statement information for the three and nine months ended September 30, 2015 and 2014 and reportable segment balance sheet information as of September 30, 2015 and December 31, 2014 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,436 $ 1,164 $ 27 $ 802 $ — $ 3 $ — (c) $ 4,432 Other Operating Segments 35 25 61 33 — 21 (175 ) — Total Revenues $ 2,471 $ 1,189 $ 88 $ 835 $ — $ 24 $ (175 ) $ 4,432 Income (Loss) from Continuing Operations $ 275 $ 113 $ 46 $ 91 $ (4 ) $ (9 ) $ — $ 512 Income from Discontinued Operations, Net of Tax — — — — 8 — — 8 Net Income (Loss) $ 275 $ 113 $ 46 $ 91 $ 4 $ (9 ) $ — $ 520 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,432 (b) $ 1,163 $ 21 $ 538 (b) $ — $ 7 $ — (c) $ 4,161 Other Operating Segments 18 (b) 68 34 363 (b) — 19 (502 ) — Total Revenues $ 2,450 $ 1,231 $ 55 $ 901 $ — $ 26 $ (502 ) $ 4,161 Income from Continuing Operations $ 220 $ 92 $ 43 $ 117 $ — $ 11 $ — $ 483 Income from Discontinued Operations, Net of Tax — — — — 11 — — 11 Net Income $ 220 $ 92 $ 43 $ 117 $ 11 $ 11 $ — $ 494 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended Revenues from: External Customers $ 7,082 $ 3,378 $ 74 $ 2,289 $ — $ 16 $ — (c) $ 12,839 Other Operating Segments 77 142 171 517 — 58 (965 ) — Total Revenues $ 7,159 $ 3,520 $ 245 $ 2,806 $ — $ 74 $ (965 ) $ 12,839 Income (Loss) from Continuing Operations $ 783 $ 288 $ 148 $ 360 $ (2 ) $ (13 ) $ — $ 1,564 Income from Discontinued Operations, Net of Tax — — — — 18 — — 18 Net Income (Loss) $ 783 $ 288 $ 148 $ 360 $ 16 $ (13 ) $ — $ 1,582 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended Revenues from: External Customers $ 7,217 (b) $ 3,388 $ 54 $ 1,932 (b) $ — $ 19 $ (51 ) (c) $ 12,559 Other Operating Segments 71 (b) 192 86 1,133 (b) — 55 (1,537 ) — Total Revenues $ 7,288 $ 3,580 $ 140 $ 3,065 $ — $ 74 $ (1,588 ) $ 12,559 Income from Continuing Operations $ 654 $ 279 $ 114 $ 378 $ 1 $ 4 $ — $ 1,430 Income from Discontinued Operations, Net of Tax — — — — 16 — — 16 Net Income $ 654 $ 279 $ 114 $ 378 $ 17 $ 4 $ — $ 1,446 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) September 30, 2015 Total Property, Plant and Equipment $ 39,981 $ 13,707 $ 3,594 $ 7,474 $ — $ 349 $ (279 ) (d) $ 64,826 Accumulated Depreciation and Amortization 12,483 3,603 43 3,390 — 178 (109 ) (d) 19,588 Total Property, Plant and Equipment - Net $ 27,498 $ 10,104 $ 3,551 $ 4,084 $ — $ 171 $ (170 ) (d) $ 45,238 Assets Held for Sale $ — $ — $ — $ — $ 608 $ — $ — $ 608 Total Assets 35,272 14,441 4,362 5,531 772 (f) 21,810 (21,089 ) (d) (e) 61,099 Long-term Debt Due Within One Year: Affiliated $ — $ — $ — $ — $ — $ — $ — $ — Nonaffiliated 949 724 — 151 — 2 — 1,826 Long-term Debt: Affiliated 20 — — 32 — — (52 ) — Nonaffiliated 9,900 4,888 1,323 641 — 848 — 17,600 Total Long-term Debt $ 10,869 $ 5,612 $ 1,323 $ 824 $ — $ 850 $ (52 ) $ 19,426 Liabilities Held for Sale $ — $ — $ — $ — $ 474 $ — $ — $ 474 (g) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2014 Total Property, Plant and Equipment $ 39,402 $ 13,024 $ 2,714 $ 8,394 $ — $ 343 $ (271 ) (d) $ 63,606 Accumulated Depreciation and Amortization 12,773 3,481 25 3,603 — 188 (99 ) (d) 19,971 Total Property, Plant and Equipment - Net $ 26,629 $ 9,543 $ 2,689 $ 4,791 $ — $ 155 $ (172 ) (d) $ 43,635 Assets Held for Sale $ — $ — $ — $ — $ 625 $ — $ — $ 625 Total Assets 33,750 14,495 3,575 6,329 749 (f) 21,081 (20,346 ) (d) (e) 59,633 Long-term Debt Due Within One Year: Affiliated $ 111 $ — $ — $ 86 $ — $ — $ (197 ) $ — Nonaffiliated 1,352 405 — 740 — 3 — 2,500 Long-term Debt: Affiliated 20 — — 32 — — (52 ) — Nonaffiliated 8,634 5,256 1,153 217 — 841 — 16,101 Total Long-term Debt $ 10,117 $ 5,661 $ 1,153 $ 1,075 $ — $ 844 $ (249 ) $ 18,601 Liabilities Held for Sale $ — $ — $ — $ — $ 435 $ — $ — $ 435 (g) (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes the impact of corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies. (f) Amounts include intercompany advances to affiliates and intercompany accounts receivable that will be settled prior to or upon the close of the sale of AEPRO. (g) Amounts include debt related to AEPRO. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. |
Appalachian Power Co [Member] | |
Business Segments | BUSINESS SEGMENTS The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business that started in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. |
Indiana Michigan Power Co [Member] | |
Business Segments | BUSINESS SEGMENTS The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business that started in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. |
Ohio Power Co [Member] | |
Business Segments | BUSINESS SEGMENTS The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business that started in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. |
Public Service Co Of Oklahoma [Member] | |
Business Segments | BUSINESS SEGMENTS The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business that started in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. |
Southwestern Electric Power Co [Member] | |
Business Segments | BUSINESS SEGMENTS The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business that started in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. |
Derivatives and Hedging
Derivatives and Hedging | 9 Months Ended |
Sep. 30, 2015 | |
Derivatives and Hedging | DERIVATIVES AND HEDGING OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS We are exposed to certain market risks as a major power producer and participant in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates. We manage these risks using derivative instruments. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies Our strategy surrounding the use of derivative instruments primarily focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. Our risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact. To accomplish our objectives, we primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. We enter into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with our energy business. We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities. We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. The following table represents the gross notional volume of our outstanding derivative contracts as of September 30, 2015 and December 31, 2014 : Notional Volume of Derivative Instruments Volume September 30, December 31, Unit of Measure Primary Risk Exposure (in millions) Commodity: Power 371 334 MWhs Coal 4 3 Tons Natural Gas 46 106 MMBtus Heating Oil and Gasoline 9 6 Gallons Interest Rate $ 114 $ 152 USD Interest Rate and Foreign Currency $ 560 $ 815 USD Fair Value Hedging Strategies We enter into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. Cash Flow Hedging Strategies We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and energy purchases. We do not hedge all commodity price risk. Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility. We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. We do not hedge all fuel price risk. We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate. We also enter into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. Our forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure. At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. We do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of our derivative instruments, we also apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with our estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of our risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2015 and December 31, 2014 condensed balance sheets, we netted $4 million and $4 million , respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $47 million and $35 million , respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities. The following tables represent the gross fair value impact of our derivative activity on our condensed balance sheets as of September 30, 2015 and December 31, 2014 : Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 311 $ 9 $ 2 $ 322 $ (179 ) $ 143 Long-term Risk Management Assets 443 3 — 446 (93 ) 353 Total Assets 754 12 2 768 (272 ) 496 Current Risk Management Liabilities 267 7 1 275 (200 ) 75 Long-term Risk Management Liabilities 293 22 1 316 (115 ) 201 Total Liabilities 560 29 2 591 (315 ) 276 Total MTM Derivative Contract Net Assets (Liabilities) $ 194 $ (17 ) $ — $ 177 $ 43 $ 220 Fair Value of Derivative Instruments December 31, 2014 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (in millions) Current Risk Management Assets $ 392 $ 30 $ 3 $ 425 $ (247 ) $ 178 Long-term Risk Management Assets 367 3 — 370 (76 ) 294 Total Assets 759 33 3 795 (323 ) 472 Current Risk Management Liabilities 329 23 1 353 (261 ) 92 Long-term Risk Management Liabilities 208 8 9 225 (94 ) 131 Total Liabilities 537 31 10 578 (355 ) 223 Total MTM Derivative Contract Net Assets (Liabilities) $ 222 $ 2 $ (7 ) $ 217 $ 32 $ 249 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The table below presents our activity of derivative risk management contracts for the three and nine months ended September 30, 2015 and 2014 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three and Nine Months Ended September 30, 2015 and 2014 Three Months Ended Nine Months Ended September 30, September 30, Location of Gain (Loss) 2015 2014 2015 2014 (in millions) Vertically Integrated Utilities Revenues $ — $ 7 $ 7 $ 29 Transmission and Distribution Utilities Revenues (1 ) — (1 ) — Generation & Marketing Revenues 1 21 60 69 Other Operation Expense — — (1 ) — Maintenance Expense (1 ) — (2 ) — Purchased Electricity for Resale 1 — 4 — Regulatory Assets (a) — (6 ) — (6 ) Regulatory Liabilities (a) (20 ) (7 ) 33 111 Total Gain (Loss) on Risk Management Contracts $ (20 ) $ 15 $ 100 $ 203 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis. Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, we designate a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our condensed statements of income. The following table shows the results of our hedging gains (losses) during the three and nine months ended September 30, 2015 and 2014 : Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 4 $ (2 ) $ 7 $ 2 Gain (Loss) on Fair Value Portion of Long-term Debt (4 ) 2 (7 ) (2 ) During the three and nine months ended September 30, 2015 and 2014 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets until the period the hedged item affects Net Income. We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power and natural gas designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2015 and 2014 , we designated power derivatives as cash flow hedges but did not designate natural gas derivatives as cash flow hedges. We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income. The impact of cash flow hedge accounting for these derivative contracts was immaterial and discontinued effective March 31, 2014. We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2015 and 2014 , we designated interest rate derivatives as cash flow hedges. The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2015 and 2014 , we did not designate any foreign currency derivatives as cash flow hedges. During the three and nine months ended September 30, 2015 and 2014 , hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above. For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2015 and 2014 , see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2015 and December 31, 2014 were: Impact of Cash Flow Hedges on the Condensed Balance Sheet September 30, 2015 Commodity Interest Rate Currency Total (in millions) Hedging Assets (a) $ 7 $ — $ 7 Hedging Liabilities (a) 24 1 25 AOCI Loss Net of Tax (11 ) (18 ) (29 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 1 (1 ) — Impact of Cash Flow Hedges on the Condensed Balance Sheet December 31, 2014 Commodity Interest Rate Total (in millions) Hedging Assets (a) $ 16 $ — $ 16 Hedging Liabilities (a) 14 1 15 AOCI Gain (Loss) Net of Tax 1 (19 ) (18 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4 (2 ) 2 (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. As of September 30, 2015 , the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions was 87 months . Credit Risk We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. We use Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. When we use standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs), we are obligated to post an additional amount of collateral for a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads and guaranties for contractual obligations if our credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP and its subsidiaries have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. The following table represents our exposure if our credit ratings were to decline below a specified rating threshold as of September 30, 2015 and December 31, 2014 : September 30, December 31, 2015 2014 (in millions) Fair Value of Contracts with Credit Downgrade Triggers $ — $ — Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement — — Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs 35 36 Amount of Collateral Attributable to Other Contracts (a) 299 281 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contracts. In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million . On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts. The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of September 30, 2015 and December 31, 2014 : September 30, December 31, (in millions) Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements $ 307 $ 235 Amount of Cash Collateral Posted 10 9 Additional Settlement Liability if Cross Default Provision is Triggered 251 178 |
Appalachian Power Co [Member] | |
Derivatives and Hedging | DERIVATIVES AND HEDGING OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30, 2015 and December 31, 2014 : Notional Volume of Derivative Instruments September 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 62,306 30,345 13,470 17,580 21,736 Coal Tons 116 1,468 — — 2,125 Natural Gas MMBtus 256 174 — — — Heating Oil and Gasoline Gallons 1,763 836 1,858 1,019 1,166 Interest Rate USD $ 2,645 $ 1,794 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — Cash Flow Hedging Strategies AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrant Subsidiaries do not hedge all commodity price risk. The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk. AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrant Subsidiaries do not hedge all interest rate exposure. At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2015 and December 31, 2014 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: September 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 1,688 $ 68 $ 98 I&M — 333 163 47 OPCo — 500 — 102 PSO — 280 — 54 SWEPCo — 319 — 62 The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of September 30, 2015 and December 31, 2014 : APCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated and Affiliated $ 34,278 $ — $ — $ 34,278 $ (6,928 ) $ 27,350 Long-term Risk Management Assets - Nonaffiliated 2,485 — — 2,485 (450 ) 2,035 Total Assets 36,763 — — 36,763 (7,378 ) 29,385 Current Risk Management Liabilities - Nonaffiliated 15,345 — — 15,345 (8,443 ) 6,902 Long-term Risk Management Liabilities - Nonaffiliated 1,596 — — 1,596 (623 ) 973 Total Liabilities 16,941 — — 16,941 (9,066 ) 7,875 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,822 $ — $ — $ 19,822 $ 1,688 $ 21,510 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated $ 32,903 $ — $ — $ 32,903 $ (9,111 ) $ 23,792 Long-term Risk Management Assets - Nonaffiliated 5,159 — — 5,159 (268 ) 4,891 Total Assets 38,062 — — 38,062 (9,379 ) 28,683 Current Risk Management Liabilities - Non Affiliated 20,161 — — 20,161 (9,144 ) 11,017 Long-term Risk Management Liabilities - Nonaffiliated 2,322 — — 2,322 (265 ) 2,057 Total Liabilities 22,483 — — 22,483 (9,409 ) 13,074 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,579 $ — $ — $ 15,579 $ 30 $ 15,609 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated and Affiliated $ 16,675 $ — $ — $ 16,675 $ (6,048 ) $ 10,627 Long-term Risk Management Assets - Nonaffiliated 1,619 — — 1,619 (281 ) 1,338 Total Assets 18,294 — — 18,294 (6,329 ) 11,965 Current Risk Management Liabilities - Nonaffiliated 10,901 — — 10,901 (6,286 ) 4,615 Long-term Risk Management Liabilities - Nonaffiliated 1,624 — — 1,624 (376 ) 1,248 Total Liabilities 12,525 — — 12,525 (6,662 ) 5,863 Total MTM Derivative Contract Net Assets (Liabilities) $ 5,769 $ — $ — $ 5,769 $ 333 $ 6,102 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated $ 28,545 $ — $ — $ 28,545 $ (6,217 ) $ 22,328 Long-term Risk Management Assets - Nonaffiliated 3,499 — — 3,499 (182 ) 3,317 Total Assets 32,044 — — 32,044 (6,399 ) 25,645 Current Risk Management Liabilities - Nonaffiliated 11,326 — — 11,326 (6,103 ) 5,223 Long-term Risk Management Liabilities - Nonaffiliated 1,575 — — 1,575 (180 ) 1,395 Total Liabilities 12,901 — — 12,901 (6,283 ) 6,618 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,143 $ — $ — $ 19,143 $ (116 ) $ 19,027 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 23,265 — — 23,265 — 23,265 Total Assets 23,265 — — 23,265 — 23,265 Current Risk Management Liabilities 3,271 — — 3,271 (448 ) 2,823 Long-term Risk Management Liabilities 4,923 — — 4,923 (52 ) 4,871 Total Liabilities 8,194 — — 8,194 (500 ) 7,694 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,071 $ — $ — $ 15,071 $ 500 $ 15,571 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 7,242 $ — $ — $ 7,242 $ — $ 7,242 Long-term Risk Management Assets 45,102 — — 45,102 — 45,102 Total Assets 52,344 — — 52,344 — 52,344 Current Risk Management Liabilities 2,045 — — 2,045 (102 ) 1,943 Long-term Risk Management Liabilities 3,013 — — 3,013 — 3,013 Total Liabilities 5,058 — — 5,058 (102 ) 4,956 Total MTM Derivative Contract Net Assets (Liabilities) $ 47,286 $ — $ — $ 47,286 $ 102 $ 47,388 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,166 $ — $ — $ 1,166 $ (131 ) $ 1,035 Long-term Risk Management Assets — — — — — — Total Assets 1,166 — — 1,166 (131 ) 1,035 Current Risk Management Liabilities 454 — — 454 (384 ) 70 Long-term Risk Management Liabilities 35 — — 35 (27 ) 8 Total Liabilities 489 — — 489 (411 ) 78 Total MTM Derivative Contract Net Assets (Liabilities) $ 677 $ — $ — $ 677 $ 280 $ 957 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 360 $ — $ — $ 360 $ (360 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 360 — — 360 (360 ) — Current Risk Management Liabilities 1,332 — — 1,332 (414 ) 918 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,332 — — 1,332 (414 ) 918 Total MTM Derivative Contract Net Assets (Liabilities) $ (972 ) $ — $ — $ (972 ) $ 54 $ (918 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,442 $ — $ — $ 1,442 $ (162 ) $ 1,280 Long-term Risk Management Assets — — — — — — Total Assets 1,442 — — 1,442 (162 ) 1,280 Current Risk Management Liabilities 1,752 — — 1,752 (450 ) 1,302 Long-term Risk Management Liabilities 788 — — 788 (31 ) 757 Total Liabilities 2,540 — — 2,540 (481 ) 2,059 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,098 ) $ — $ — $ (1,098 ) $ 319 $ (779 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 471 $ — $ — $ 471 $ (440 ) $ 31 Long-term Risk Management Assets — — — — — — Total Assets 471 — — 471 (440 ) 31 Current Risk Management Liabilities 1,584 — — 1,584 (502 ) 1,082 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,584 — — 1,584 (502 ) 1,082 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,113 ) $ — $ — $ (1,113 ) $ 62 $ (1,051 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and nine months ended September 30, 2015 and 2014 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ (369 ) $ 350 $ (917 ) $ (9 ) $ (7 ) Sales to AEP Affiliates 1,156 3,336 — — — Other Operation Expense (88 ) (63 ) (128 ) (109 ) (127 ) Maintenance Expense (164 ) (86 ) (140 ) (88 ) (88 ) Purchased Electricity for Resale 831 15 30 — — Regulatory Assets (a) 861 (981 ) — (190 ) 188 Regulatory Liabilities (a) 3,197 (1,718 ) (22,281 ) (498 ) 1,137 Total Gain (Loss) on Risk Management Contracts $ 5,424 $ 853 $ (23,436 ) $ (894 ) $ 1,103 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,231 $ 2,988 $ 41 $ 45 $ 74 Sales to AEP Affiliates — (196 ) — 196 — Regulatory Assets (a) (2,571 ) (471 ) (852 ) (109 ) (284 ) Regulatory Liabilities (a) (3,606 ) (176 ) (1,555 ) 120 (180 ) Total Gain (Loss) on Risk Management Contracts $ (4,946 ) $ 2,145 $ (2,366 ) $ 252 $ (390 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 790 $ 3,591 $ (882 ) $ 16 $ 19 Sales to AEP Affiliates 1,511 4,341 — — — Other Operation Expense (287 ) (221 ) (389 ) (307 ) (373 ) Maintenance Expense (503 ) (221 ) (396 ) (248 ) (265 ) Purchased Electricity for Resale 1,571 347 30 — — Regulatory Assets (a) 2,136 (1,213 ) — 615 (1,234 ) Regulatory Liabilities (a) 31,797 4,121 (24,880 ) 5,076 14,446 Total Gain (Loss) on Risk Management Contracts $ 37,015 $ 10,745 $ (26,517 ) $ 5,152 $ 12,593 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 7,262 $ 10,467 $ 97 $ 172 $ 18 Sales to AEP Affiliates — (717 ) — 717 — Regulatory Assets (a) (2,567 ) (471 ) (215 ) (119 ) (285 ) Regulatory Liabilities (a) 42,444 26,934 39,311 (69 ) 119 Total Gain (Loss) on Risk Management Contracts $ 47,139 $ 36,213 $ 39,193 $ 701 $ (148 ) (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2015 , the Registrant Subsidiaries did not designate power derivatives as cash flow hedges. During the three and nine months ended September 30, 2014 , APCo and I&M designated power derivatives as cash flow hedges. The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014. The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2015 and 2014 , the Registrant Subsidiaries did not designate interest rate derivatives as cash flow hedges. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2015 and 2014 , the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and nine months ended September 30, 2015 and 2014 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2015 and 2014 , see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2015 and December 31, 2014 were: Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets September 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,805 I&M — — — — — (13,604 ) OPCo — — — — — 4,572 PSO — — — — — 4,374 SWEPCo — — — — — (9,470 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 734 0 I&M — (1,277 ) 0 OPCo — 1,282 0 PSO — 771 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate g |
Indiana Michigan Power Co [Member] | |
Derivatives and Hedging | DERIVATIVES AND HEDGING OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30, 2015 and December 31, 2014 : Notional Volume of Derivative Instruments September 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 62,306 30,345 13,470 17,580 21,736 Coal Tons 116 1,468 — — 2,125 Natural Gas MMBtus 256 174 — — — Heating Oil and Gasoline Gallons 1,763 836 1,858 1,019 1,166 Interest Rate USD $ 2,645 $ 1,794 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — Cash Flow Hedging Strategies AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrant Subsidiaries do not hedge all commodity price risk. The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk. AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrant Subsidiaries do not hedge all interest rate exposure. At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2015 and December 31, 2014 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: September 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 1,688 $ 68 $ 98 I&M — 333 163 47 OPCo — 500 — 102 PSO — 280 — 54 SWEPCo — 319 — 62 The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of September 30, 2015 and December 31, 2014 : APCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated and Affiliated $ 34,278 $ — $ — $ 34,278 $ (6,928 ) $ 27,350 Long-term Risk Management Assets - Nonaffiliated 2,485 — — 2,485 (450 ) 2,035 Total Assets 36,763 — — 36,763 (7,378 ) 29,385 Current Risk Management Liabilities - Nonaffiliated 15,345 — — 15,345 (8,443 ) 6,902 Long-term Risk Management Liabilities - Nonaffiliated 1,596 — — 1,596 (623 ) 973 Total Liabilities 16,941 — — 16,941 (9,066 ) 7,875 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,822 $ — $ — $ 19,822 $ 1,688 $ 21,510 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated $ 32,903 $ — $ — $ 32,903 $ (9,111 ) $ 23,792 Long-term Risk Management Assets - Nonaffiliated 5,159 — — 5,159 (268 ) 4,891 Total Assets 38,062 — — 38,062 (9,379 ) 28,683 Current Risk Management Liabilities - Non Affiliated 20,161 — — 20,161 (9,144 ) 11,017 Long-term Risk Management Liabilities - Nonaffiliated 2,322 — — 2,322 (265 ) 2,057 Total Liabilities 22,483 — — 22,483 (9,409 ) 13,074 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,579 $ — $ — $ 15,579 $ 30 $ 15,609 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated and Affiliated $ 16,675 $ — $ — $ 16,675 $ (6,048 ) $ 10,627 Long-term Risk Management Assets - Nonaffiliated 1,619 — — 1,619 (281 ) 1,338 Total Assets 18,294 — — 18,294 (6,329 ) 11,965 Current Risk Management Liabilities - Nonaffiliated 10,901 — — 10,901 (6,286 ) 4,615 Long-term Risk Management Liabilities - Nonaffiliated 1,624 — — 1,624 (376 ) 1,248 Total Liabilities 12,525 — — 12,525 (6,662 ) 5,863 Total MTM Derivative Contract Net Assets (Liabilities) $ 5,769 $ — $ — $ 5,769 $ 333 $ 6,102 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated $ 28,545 $ — $ — $ 28,545 $ (6,217 ) $ 22,328 Long-term Risk Management Assets - Nonaffiliated 3,499 — — 3,499 (182 ) 3,317 Total Assets 32,044 — — 32,044 (6,399 ) 25,645 Current Risk Management Liabilities - Nonaffiliated 11,326 — — 11,326 (6,103 ) 5,223 Long-term Risk Management Liabilities - Nonaffiliated 1,575 — — 1,575 (180 ) 1,395 Total Liabilities 12,901 — — 12,901 (6,283 ) 6,618 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,143 $ — $ — $ 19,143 $ (116 ) $ 19,027 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 23,265 — — 23,265 — 23,265 Total Assets 23,265 — — 23,265 — 23,265 Current Risk Management Liabilities 3,271 — — 3,271 (448 ) 2,823 Long-term Risk Management Liabilities 4,923 — — 4,923 (52 ) 4,871 Total Liabilities 8,194 — — 8,194 (500 ) 7,694 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,071 $ — $ — $ 15,071 $ 500 $ 15,571 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 7,242 $ — $ — $ 7,242 $ — $ 7,242 Long-term Risk Management Assets 45,102 — — 45,102 — 45,102 Total Assets 52,344 — — 52,344 — 52,344 Current Risk Management Liabilities 2,045 — — 2,045 (102 ) 1,943 Long-term Risk Management Liabilities 3,013 — — 3,013 — 3,013 Total Liabilities 5,058 — — 5,058 (102 ) 4,956 Total MTM Derivative Contract Net Assets (Liabilities) $ 47,286 $ — $ — $ 47,286 $ 102 $ 47,388 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,166 $ — $ — $ 1,166 $ (131 ) $ 1,035 Long-term Risk Management Assets — — — — — — Total Assets 1,166 — — 1,166 (131 ) 1,035 Current Risk Management Liabilities 454 — — 454 (384 ) 70 Long-term Risk Management Liabilities 35 — — 35 (27 ) 8 Total Liabilities 489 — — 489 (411 ) 78 Total MTM Derivative Contract Net Assets (Liabilities) $ 677 $ — $ — $ 677 $ 280 $ 957 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 360 $ — $ — $ 360 $ (360 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 360 — — 360 (360 ) — Current Risk Management Liabilities 1,332 — — 1,332 (414 ) 918 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,332 — — 1,332 (414 ) 918 Total MTM Derivative Contract Net Assets (Liabilities) $ (972 ) $ — $ — $ (972 ) $ 54 $ (918 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,442 $ — $ — $ 1,442 $ (162 ) $ 1,280 Long-term Risk Management Assets — — — — — — Total Assets 1,442 — — 1,442 (162 ) 1,280 Current Risk Management Liabilities 1,752 — — 1,752 (450 ) 1,302 Long-term Risk Management Liabilities 788 — — 788 (31 ) 757 Total Liabilities 2,540 — — 2,540 (481 ) 2,059 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,098 ) $ — $ — $ (1,098 ) $ 319 $ (779 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 471 $ — $ — $ 471 $ (440 ) $ 31 Long-term Risk Management Assets — — — — — — Total Assets 471 — — 471 (440 ) 31 Current Risk Management Liabilities 1,584 — — 1,584 (502 ) 1,082 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,584 — — 1,584 (502 ) 1,082 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,113 ) $ — $ — $ (1,113 ) $ 62 $ (1,051 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and nine months ended September 30, 2015 and 2014 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ (369 ) $ 350 $ (917 ) $ (9 ) $ (7 ) Sales to AEP Affiliates 1,156 3,336 — — — Other Operation Expense (88 ) (63 ) (128 ) (109 ) (127 ) Maintenance Expense (164 ) (86 ) (140 ) (88 ) (88 ) Purchased Electricity for Resale 831 15 30 — — Regulatory Assets (a) 861 (981 ) — (190 ) 188 Regulatory Liabilities (a) 3,197 (1,718 ) (22,281 ) (498 ) 1,137 Total Gain (Loss) on Risk Management Contracts $ 5,424 $ 853 $ (23,436 ) $ (894 ) $ 1,103 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,231 $ 2,988 $ 41 $ 45 $ 74 Sales to AEP Affiliates — (196 ) — 196 — Regulatory Assets (a) (2,571 ) (471 ) (852 ) (109 ) (284 ) Regulatory Liabilities (a) (3,606 ) (176 ) (1,555 ) 120 (180 ) Total Gain (Loss) on Risk Management Contracts $ (4,946 ) $ 2,145 $ (2,366 ) $ 252 $ (390 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 790 $ 3,591 $ (882 ) $ 16 $ 19 Sales to AEP Affiliates 1,511 4,341 — — — Other Operation Expense (287 ) (221 ) (389 ) (307 ) (373 ) Maintenance Expense (503 ) (221 ) (396 ) (248 ) (265 ) Purchased Electricity for Resale 1,571 347 30 — — Regulatory Assets (a) 2,136 (1,213 ) — 615 (1,234 ) Regulatory Liabilities (a) 31,797 4,121 (24,880 ) 5,076 14,446 Total Gain (Loss) on Risk Management Contracts $ 37,015 $ 10,745 $ (26,517 ) $ 5,152 $ 12,593 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 7,262 $ 10,467 $ 97 $ 172 $ 18 Sales to AEP Affiliates — (717 ) — 717 — Regulatory Assets (a) (2,567 ) (471 ) (215 ) (119 ) (285 ) Regulatory Liabilities (a) 42,444 26,934 39,311 (69 ) 119 Total Gain (Loss) on Risk Management Contracts $ 47,139 $ 36,213 $ 39,193 $ 701 $ (148 ) (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2015 , the Registrant Subsidiaries did not designate power derivatives as cash flow hedges. During the three and nine months ended September 30, 2014 , APCo and I&M designated power derivatives as cash flow hedges. The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014. The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2015 and 2014 , the Registrant Subsidiaries did not designate interest rate derivatives as cash flow hedges. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2015 and 2014 , the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and nine months ended September 30, 2015 and 2014 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2015 and 2014 , see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2015 and December 31, 2014 were: Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets September 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,805 I&M — — — — — (13,604 ) OPCo — — — — — 4,572 PSO — — — — — 4,374 SWEPCo — — — — — (9,470 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 734 0 I&M — (1,277 ) 0 OPCo — 1,282 0 PSO — 771 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate g |
Ohio Power Co [Member] | |
Derivatives and Hedging | DERIVATIVES AND HEDGING OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30, 2015 and December 31, 2014 : Notional Volume of Derivative Instruments September 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 62,306 30,345 13,470 17,580 21,736 Coal Tons 116 1,468 — — 2,125 Natural Gas MMBtus 256 174 — — — Heating Oil and Gasoline Gallons 1,763 836 1,858 1,019 1,166 Interest Rate USD $ 2,645 $ 1,794 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — Cash Flow Hedging Strategies AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrant Subsidiaries do not hedge all commodity price risk. The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk. AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrant Subsidiaries do not hedge all interest rate exposure. At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2015 and December 31, 2014 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: September 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 1,688 $ 68 $ 98 I&M — 333 163 47 OPCo — 500 — 102 PSO — 280 — 54 SWEPCo — 319 — 62 The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of September 30, 2015 and December 31, 2014 : APCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated and Affiliated $ 34,278 $ — $ — $ 34,278 $ (6,928 ) $ 27,350 Long-term Risk Management Assets - Nonaffiliated 2,485 — — 2,485 (450 ) 2,035 Total Assets 36,763 — — 36,763 (7,378 ) 29,385 Current Risk Management Liabilities - Nonaffiliated 15,345 — — 15,345 (8,443 ) 6,902 Long-term Risk Management Liabilities - Nonaffiliated 1,596 — — 1,596 (623 ) 973 Total Liabilities 16,941 — — 16,941 (9,066 ) 7,875 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,822 $ — $ — $ 19,822 $ 1,688 $ 21,510 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated $ 32,903 $ — $ — $ 32,903 $ (9,111 ) $ 23,792 Long-term Risk Management Assets - Nonaffiliated 5,159 — — 5,159 (268 ) 4,891 Total Assets 38,062 — — 38,062 (9,379 ) 28,683 Current Risk Management Liabilities - Non Affiliated 20,161 — — 20,161 (9,144 ) 11,017 Long-term Risk Management Liabilities - Nonaffiliated 2,322 — — 2,322 (265 ) 2,057 Total Liabilities 22,483 — — 22,483 (9,409 ) 13,074 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,579 $ — $ — $ 15,579 $ 30 $ 15,609 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated and Affiliated $ 16,675 $ — $ — $ 16,675 $ (6,048 ) $ 10,627 Long-term Risk Management Assets - Nonaffiliated 1,619 — — 1,619 (281 ) 1,338 Total Assets 18,294 — — 18,294 (6,329 ) 11,965 Current Risk Management Liabilities - Nonaffiliated 10,901 — — 10,901 (6,286 ) 4,615 Long-term Risk Management Liabilities - Nonaffiliated 1,624 — — 1,624 (376 ) 1,248 Total Liabilities 12,525 — — 12,525 (6,662 ) 5,863 Total MTM Derivative Contract Net Assets (Liabilities) $ 5,769 $ — $ — $ 5,769 $ 333 $ 6,102 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated $ 28,545 $ — $ — $ 28,545 $ (6,217 ) $ 22,328 Long-term Risk Management Assets - Nonaffiliated 3,499 — — 3,499 (182 ) 3,317 Total Assets 32,044 — — 32,044 (6,399 ) 25,645 Current Risk Management Liabilities - Nonaffiliated 11,326 — — 11,326 (6,103 ) 5,223 Long-term Risk Management Liabilities - Nonaffiliated 1,575 — — 1,575 (180 ) 1,395 Total Liabilities 12,901 — — 12,901 (6,283 ) 6,618 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,143 $ — $ — $ 19,143 $ (116 ) $ 19,027 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 23,265 — — 23,265 — 23,265 Total Assets 23,265 — — 23,265 — 23,265 Current Risk Management Liabilities 3,271 — — 3,271 (448 ) 2,823 Long-term Risk Management Liabilities 4,923 — — 4,923 (52 ) 4,871 Total Liabilities 8,194 — — 8,194 (500 ) 7,694 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,071 $ — $ — $ 15,071 $ 500 $ 15,571 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 7,242 $ — $ — $ 7,242 $ — $ 7,242 Long-term Risk Management Assets 45,102 — — 45,102 — 45,102 Total Assets 52,344 — — 52,344 — 52,344 Current Risk Management Liabilities 2,045 — — 2,045 (102 ) 1,943 Long-term Risk Management Liabilities 3,013 — — 3,013 — 3,013 Total Liabilities 5,058 — — 5,058 (102 ) 4,956 Total MTM Derivative Contract Net Assets (Liabilities) $ 47,286 $ — $ — $ 47,286 $ 102 $ 47,388 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,166 $ — $ — $ 1,166 $ (131 ) $ 1,035 Long-term Risk Management Assets — — — — — — Total Assets 1,166 — — 1,166 (131 ) 1,035 Current Risk Management Liabilities 454 — — 454 (384 ) 70 Long-term Risk Management Liabilities 35 — — 35 (27 ) 8 Total Liabilities 489 — — 489 (411 ) 78 Total MTM Derivative Contract Net Assets (Liabilities) $ 677 $ — $ — $ 677 $ 280 $ 957 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 360 $ — $ — $ 360 $ (360 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 360 — — 360 (360 ) — Current Risk Management Liabilities 1,332 — — 1,332 (414 ) 918 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,332 — — 1,332 (414 ) 918 Total MTM Derivative Contract Net Assets (Liabilities) $ (972 ) $ — $ — $ (972 ) $ 54 $ (918 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,442 $ — $ — $ 1,442 $ (162 ) $ 1,280 Long-term Risk Management Assets — — — — — — Total Assets 1,442 — — 1,442 (162 ) 1,280 Current Risk Management Liabilities 1,752 — — 1,752 (450 ) 1,302 Long-term Risk Management Liabilities 788 — — 788 (31 ) 757 Total Liabilities 2,540 — — 2,540 (481 ) 2,059 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,098 ) $ — $ — $ (1,098 ) $ 319 $ (779 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 471 $ — $ — $ 471 $ (440 ) $ 31 Long-term Risk Management Assets — — — — — — Total Assets 471 — — 471 (440 ) 31 Current Risk Management Liabilities 1,584 — — 1,584 (502 ) 1,082 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,584 — — 1,584 (502 ) 1,082 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,113 ) $ — $ — $ (1,113 ) $ 62 $ (1,051 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and nine months ended September 30, 2015 and 2014 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ (369 ) $ 350 $ (917 ) $ (9 ) $ (7 ) Sales to AEP Affiliates 1,156 3,336 — — — Other Operation Expense (88 ) (63 ) (128 ) (109 ) (127 ) Maintenance Expense (164 ) (86 ) (140 ) (88 ) (88 ) Purchased Electricity for Resale 831 15 30 — — Regulatory Assets (a) 861 (981 ) — (190 ) 188 Regulatory Liabilities (a) 3,197 (1,718 ) (22,281 ) (498 ) 1,137 Total Gain (Loss) on Risk Management Contracts $ 5,424 $ 853 $ (23,436 ) $ (894 ) $ 1,103 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,231 $ 2,988 $ 41 $ 45 $ 74 Sales to AEP Affiliates — (196 ) — 196 — Regulatory Assets (a) (2,571 ) (471 ) (852 ) (109 ) (284 ) Regulatory Liabilities (a) (3,606 ) (176 ) (1,555 ) 120 (180 ) Total Gain (Loss) on Risk Management Contracts $ (4,946 ) $ 2,145 $ (2,366 ) $ 252 $ (390 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 790 $ 3,591 $ (882 ) $ 16 $ 19 Sales to AEP Affiliates 1,511 4,341 — — — Other Operation Expense (287 ) (221 ) (389 ) (307 ) (373 ) Maintenance Expense (503 ) (221 ) (396 ) (248 ) (265 ) Purchased Electricity for Resale 1,571 347 30 — — Regulatory Assets (a) 2,136 (1,213 ) — 615 (1,234 ) Regulatory Liabilities (a) 31,797 4,121 (24,880 ) 5,076 14,446 Total Gain (Loss) on Risk Management Contracts $ 37,015 $ 10,745 $ (26,517 ) $ 5,152 $ 12,593 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 7,262 $ 10,467 $ 97 $ 172 $ 18 Sales to AEP Affiliates — (717 ) — 717 — Regulatory Assets (a) (2,567 ) (471 ) (215 ) (119 ) (285 ) Regulatory Liabilities (a) 42,444 26,934 39,311 (69 ) 119 Total Gain (Loss) on Risk Management Contracts $ 47,139 $ 36,213 $ 39,193 $ 701 $ (148 ) (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2015 , the Registrant Subsidiaries did not designate power derivatives as cash flow hedges. During the three and nine months ended September 30, 2014 , APCo and I&M designated power derivatives as cash flow hedges. The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014. The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2015 and 2014 , the Registrant Subsidiaries did not designate interest rate derivatives as cash flow hedges. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2015 and 2014 , the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and nine months ended September 30, 2015 and 2014 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2015 and 2014 , see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2015 and December 31, 2014 were: Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets September 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,805 I&M — — — — — (13,604 ) OPCo — — — — — 4,572 PSO — — — — — 4,374 SWEPCo — — — — — (9,470 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 734 0 I&M — (1,277 ) 0 OPCo — 1,282 0 PSO — 771 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate g |
Public Service Co Of Oklahoma [Member] | |
Derivatives and Hedging | DERIVATIVES AND HEDGING OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30, 2015 and December 31, 2014 : Notional Volume of Derivative Instruments September 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 62,306 30,345 13,470 17,580 21,736 Coal Tons 116 1,468 — — 2,125 Natural Gas MMBtus 256 174 — — — Heating Oil and Gasoline Gallons 1,763 836 1,858 1,019 1,166 Interest Rate USD $ 2,645 $ 1,794 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — Cash Flow Hedging Strategies AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrant Subsidiaries do not hedge all commodity price risk. The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk. AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrant Subsidiaries do not hedge all interest rate exposure. At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2015 and December 31, 2014 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: September 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 1,688 $ 68 $ 98 I&M — 333 163 47 OPCo — 500 — 102 PSO — 280 — 54 SWEPCo — 319 — 62 The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of September 30, 2015 and December 31, 2014 : APCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated and Affiliated $ 34,278 $ — $ — $ 34,278 $ (6,928 ) $ 27,350 Long-term Risk Management Assets - Nonaffiliated 2,485 — — 2,485 (450 ) 2,035 Total Assets 36,763 — — 36,763 (7,378 ) 29,385 Current Risk Management Liabilities - Nonaffiliated 15,345 — — 15,345 (8,443 ) 6,902 Long-term Risk Management Liabilities - Nonaffiliated 1,596 — — 1,596 (623 ) 973 Total Liabilities 16,941 — — 16,941 (9,066 ) 7,875 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,822 $ — $ — $ 19,822 $ 1,688 $ 21,510 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated $ 32,903 $ — $ — $ 32,903 $ (9,111 ) $ 23,792 Long-term Risk Management Assets - Nonaffiliated 5,159 — — 5,159 (268 ) 4,891 Total Assets 38,062 — — 38,062 (9,379 ) 28,683 Current Risk Management Liabilities - Non Affiliated 20,161 — — 20,161 (9,144 ) 11,017 Long-term Risk Management Liabilities - Nonaffiliated 2,322 — — 2,322 (265 ) 2,057 Total Liabilities 22,483 — — 22,483 (9,409 ) 13,074 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,579 $ — $ — $ 15,579 $ 30 $ 15,609 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated and Affiliated $ 16,675 $ — $ — $ 16,675 $ (6,048 ) $ 10,627 Long-term Risk Management Assets - Nonaffiliated 1,619 — — 1,619 (281 ) 1,338 Total Assets 18,294 — — 18,294 (6,329 ) 11,965 Current Risk Management Liabilities - Nonaffiliated 10,901 — — 10,901 (6,286 ) 4,615 Long-term Risk Management Liabilities - Nonaffiliated 1,624 — — 1,624 (376 ) 1,248 Total Liabilities 12,525 — — 12,525 (6,662 ) 5,863 Total MTM Derivative Contract Net Assets (Liabilities) $ 5,769 $ — $ — $ 5,769 $ 333 $ 6,102 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated $ 28,545 $ — $ — $ 28,545 $ (6,217 ) $ 22,328 Long-term Risk Management Assets - Nonaffiliated 3,499 — — 3,499 (182 ) 3,317 Total Assets 32,044 — — 32,044 (6,399 ) 25,645 Current Risk Management Liabilities - Nonaffiliated 11,326 — — 11,326 (6,103 ) 5,223 Long-term Risk Management Liabilities - Nonaffiliated 1,575 — — 1,575 (180 ) 1,395 Total Liabilities 12,901 — — 12,901 (6,283 ) 6,618 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,143 $ — $ — $ 19,143 $ (116 ) $ 19,027 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 23,265 — — 23,265 — 23,265 Total Assets 23,265 — — 23,265 — 23,265 Current Risk Management Liabilities 3,271 — — 3,271 (448 ) 2,823 Long-term Risk Management Liabilities 4,923 — — 4,923 (52 ) 4,871 Total Liabilities 8,194 — — 8,194 (500 ) 7,694 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,071 $ — $ — $ 15,071 $ 500 $ 15,571 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 7,242 $ — $ — $ 7,242 $ — $ 7,242 Long-term Risk Management Assets 45,102 — — 45,102 — 45,102 Total Assets 52,344 — — 52,344 — 52,344 Current Risk Management Liabilities 2,045 — — 2,045 (102 ) 1,943 Long-term Risk Management Liabilities 3,013 — — 3,013 — 3,013 Total Liabilities 5,058 — — 5,058 (102 ) 4,956 Total MTM Derivative Contract Net Assets (Liabilities) $ 47,286 $ — $ — $ 47,286 $ 102 $ 47,388 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,166 $ — $ — $ 1,166 $ (131 ) $ 1,035 Long-term Risk Management Assets — — — — — — Total Assets 1,166 — — 1,166 (131 ) 1,035 Current Risk Management Liabilities 454 — — 454 (384 ) 70 Long-term Risk Management Liabilities 35 — — 35 (27 ) 8 Total Liabilities 489 — — 489 (411 ) 78 Total MTM Derivative Contract Net Assets (Liabilities) $ 677 $ — $ — $ 677 $ 280 $ 957 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 360 $ — $ — $ 360 $ (360 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 360 — — 360 (360 ) — Current Risk Management Liabilities 1,332 — — 1,332 (414 ) 918 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,332 — — 1,332 (414 ) 918 Total MTM Derivative Contract Net Assets (Liabilities) $ (972 ) $ — $ — $ (972 ) $ 54 $ (918 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,442 $ — $ — $ 1,442 $ (162 ) $ 1,280 Long-term Risk Management Assets — — — — — — Total Assets 1,442 — — 1,442 (162 ) 1,280 Current Risk Management Liabilities 1,752 — — 1,752 (450 ) 1,302 Long-term Risk Management Liabilities 788 — — 788 (31 ) 757 Total Liabilities 2,540 — — 2,540 (481 ) 2,059 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,098 ) $ — $ — $ (1,098 ) $ 319 $ (779 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 471 $ — $ — $ 471 $ (440 ) $ 31 Long-term Risk Management Assets — — — — — — Total Assets 471 — — 471 (440 ) 31 Current Risk Management Liabilities 1,584 — — 1,584 (502 ) 1,082 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,584 — — 1,584 (502 ) 1,082 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,113 ) $ — $ — $ (1,113 ) $ 62 $ (1,051 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and nine months ended September 30, 2015 and 2014 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ (369 ) $ 350 $ (917 ) $ (9 ) $ (7 ) Sales to AEP Affiliates 1,156 3,336 — — — Other Operation Expense (88 ) (63 ) (128 ) (109 ) (127 ) Maintenance Expense (164 ) (86 ) (140 ) (88 ) (88 ) Purchased Electricity for Resale 831 15 30 — — Regulatory Assets (a) 861 (981 ) — (190 ) 188 Regulatory Liabilities (a) 3,197 (1,718 ) (22,281 ) (498 ) 1,137 Total Gain (Loss) on Risk Management Contracts $ 5,424 $ 853 $ (23,436 ) $ (894 ) $ 1,103 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,231 $ 2,988 $ 41 $ 45 $ 74 Sales to AEP Affiliates — (196 ) — 196 — Regulatory Assets (a) (2,571 ) (471 ) (852 ) (109 ) (284 ) Regulatory Liabilities (a) (3,606 ) (176 ) (1,555 ) 120 (180 ) Total Gain (Loss) on Risk Management Contracts $ (4,946 ) $ 2,145 $ (2,366 ) $ 252 $ (390 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 790 $ 3,591 $ (882 ) $ 16 $ 19 Sales to AEP Affiliates 1,511 4,341 — — — Other Operation Expense (287 ) (221 ) (389 ) (307 ) (373 ) Maintenance Expense (503 ) (221 ) (396 ) (248 ) (265 ) Purchased Electricity for Resale 1,571 347 30 — — Regulatory Assets (a) 2,136 (1,213 ) — 615 (1,234 ) Regulatory Liabilities (a) 31,797 4,121 (24,880 ) 5,076 14,446 Total Gain (Loss) on Risk Management Contracts $ 37,015 $ 10,745 $ (26,517 ) $ 5,152 $ 12,593 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 7,262 $ 10,467 $ 97 $ 172 $ 18 Sales to AEP Affiliates — (717 ) — 717 — Regulatory Assets (a) (2,567 ) (471 ) (215 ) (119 ) (285 ) Regulatory Liabilities (a) 42,444 26,934 39,311 (69 ) 119 Total Gain (Loss) on Risk Management Contracts $ 47,139 $ 36,213 $ 39,193 $ 701 $ (148 ) (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2015 , the Registrant Subsidiaries did not designate power derivatives as cash flow hedges. During the three and nine months ended September 30, 2014 , APCo and I&M designated power derivatives as cash flow hedges. The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014. The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2015 and 2014 , the Registrant Subsidiaries did not designate interest rate derivatives as cash flow hedges. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2015 and 2014 , the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and nine months ended September 30, 2015 and 2014 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2015 and 2014 , see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2015 and December 31, 2014 were: Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets September 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,805 I&M — — — — — (13,604 ) OPCo — — — — — 4,572 PSO — — — — — 4,374 SWEPCo — — — — — (9,470 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 734 0 I&M — (1,277 ) 0 OPCo — 1,282 0 PSO — 771 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate g |
Southwestern Electric Power Co [Member] | |
Derivatives and Hedging | DERIVATIVES AND HEDGING OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30, 2015 and December 31, 2014 : Notional Volume of Derivative Instruments September 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 62,306 30,345 13,470 17,580 21,736 Coal Tons 116 1,468 — — 2,125 Natural Gas MMBtus 256 174 — — — Heating Oil and Gasoline Gallons 1,763 836 1,858 1,019 1,166 Interest Rate USD $ 2,645 $ 1,794 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — Cash Flow Hedging Strategies AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrant Subsidiaries do not hedge all commodity price risk. The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk. AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrant Subsidiaries do not hedge all interest rate exposure. At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2015 and December 31, 2014 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: September 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 1,688 $ 68 $ 98 I&M — 333 163 47 OPCo — 500 — 102 PSO — 280 — 54 SWEPCo — 319 — 62 The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of September 30, 2015 and December 31, 2014 : APCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated and Affiliated $ 34,278 $ — $ — $ 34,278 $ (6,928 ) $ 27,350 Long-term Risk Management Assets - Nonaffiliated 2,485 — — 2,485 (450 ) 2,035 Total Assets 36,763 — — 36,763 (7,378 ) 29,385 Current Risk Management Liabilities - Nonaffiliated 15,345 — — 15,345 (8,443 ) 6,902 Long-term Risk Management Liabilities - Nonaffiliated 1,596 — — 1,596 (623 ) 973 Total Liabilities 16,941 — — 16,941 (9,066 ) 7,875 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,822 $ — $ — $ 19,822 $ 1,688 $ 21,510 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated $ 32,903 $ — $ — $ 32,903 $ (9,111 ) $ 23,792 Long-term Risk Management Assets - Nonaffiliated 5,159 — — 5,159 (268 ) 4,891 Total Assets 38,062 — — 38,062 (9,379 ) 28,683 Current Risk Management Liabilities - Non Affiliated 20,161 — — 20,161 (9,144 ) 11,017 Long-term Risk Management Liabilities - Nonaffiliated 2,322 — — 2,322 (265 ) 2,057 Total Liabilities 22,483 — — 22,483 (9,409 ) 13,074 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,579 $ — $ — $ 15,579 $ 30 $ 15,609 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated and Affiliated $ 16,675 $ — $ — $ 16,675 $ (6,048 ) $ 10,627 Long-term Risk Management Assets - Nonaffiliated 1,619 — — 1,619 (281 ) 1,338 Total Assets 18,294 — — 18,294 (6,329 ) 11,965 Current Risk Management Liabilities - Nonaffiliated 10,901 — — 10,901 (6,286 ) 4,615 Long-term Risk Management Liabilities - Nonaffiliated 1,624 — — 1,624 (376 ) 1,248 Total Liabilities 12,525 — — 12,525 (6,662 ) 5,863 Total MTM Derivative Contract Net Assets (Liabilities) $ 5,769 $ — $ — $ 5,769 $ 333 $ 6,102 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated $ 28,545 $ — $ — $ 28,545 $ (6,217 ) $ 22,328 Long-term Risk Management Assets - Nonaffiliated 3,499 — — 3,499 (182 ) 3,317 Total Assets 32,044 — — 32,044 (6,399 ) 25,645 Current Risk Management Liabilities - Nonaffiliated 11,326 — — 11,326 (6,103 ) 5,223 Long-term Risk Management Liabilities - Nonaffiliated 1,575 — — 1,575 (180 ) 1,395 Total Liabilities 12,901 — — 12,901 (6,283 ) 6,618 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,143 $ — $ — $ 19,143 $ (116 ) $ 19,027 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 23,265 — — 23,265 — 23,265 Total Assets 23,265 — — 23,265 — 23,265 Current Risk Management Liabilities 3,271 — — 3,271 (448 ) 2,823 Long-term Risk Management Liabilities 4,923 — — 4,923 (52 ) 4,871 Total Liabilities 8,194 — — 8,194 (500 ) 7,694 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,071 $ — $ — $ 15,071 $ 500 $ 15,571 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 7,242 $ — $ — $ 7,242 $ — $ 7,242 Long-term Risk Management Assets 45,102 — — 45,102 — 45,102 Total Assets 52,344 — — 52,344 — 52,344 Current Risk Management Liabilities 2,045 — — 2,045 (102 ) 1,943 Long-term Risk Management Liabilities 3,013 — — 3,013 — 3,013 Total Liabilities 5,058 — — 5,058 (102 ) 4,956 Total MTM Derivative Contract Net Assets (Liabilities) $ 47,286 $ — $ — $ 47,286 $ 102 $ 47,388 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,166 $ — $ — $ 1,166 $ (131 ) $ 1,035 Long-term Risk Management Assets — — — — — — Total Assets 1,166 — — 1,166 (131 ) 1,035 Current Risk Management Liabilities 454 — — 454 (384 ) 70 Long-term Risk Management Liabilities 35 — — 35 (27 ) 8 Total Liabilities 489 — — 489 (411 ) 78 Total MTM Derivative Contract Net Assets (Liabilities) $ 677 $ — $ — $ 677 $ 280 $ 957 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 360 $ — $ — $ 360 $ (360 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 360 — — 360 (360 ) — Current Risk Management Liabilities 1,332 — — 1,332 (414 ) 918 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,332 — — 1,332 (414 ) 918 Total MTM Derivative Contract Net Assets (Liabilities) $ (972 ) $ — $ — $ (972 ) $ 54 $ (918 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,442 $ — $ — $ 1,442 $ (162 ) $ 1,280 Long-term Risk Management Assets — — — — — — Total Assets 1,442 — — 1,442 (162 ) 1,280 Current Risk Management Liabilities 1,752 — — 1,752 (450 ) 1,302 Long-term Risk Management Liabilities 788 — — 788 (31 ) 757 Total Liabilities 2,540 — — 2,540 (481 ) 2,059 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,098 ) $ — $ — $ (1,098 ) $ 319 $ (779 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 471 $ — $ — $ 471 $ (440 ) $ 31 Long-term Risk Management Assets — — — — — — Total Assets 471 — — 471 (440 ) 31 Current Risk Management Liabilities 1,584 — — 1,584 (502 ) 1,082 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,584 — — 1,584 (502 ) 1,082 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,113 ) $ — $ — $ (1,113 ) $ 62 $ (1,051 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and nine months ended September 30, 2015 and 2014 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ (369 ) $ 350 $ (917 ) $ (9 ) $ (7 ) Sales to AEP Affiliates 1,156 3,336 — — — Other Operation Expense (88 ) (63 ) (128 ) (109 ) (127 ) Maintenance Expense (164 ) (86 ) (140 ) (88 ) (88 ) Purchased Electricity for Resale 831 15 30 — — Regulatory Assets (a) 861 (981 ) — (190 ) 188 Regulatory Liabilities (a) 3,197 (1,718 ) (22,281 ) (498 ) 1,137 Total Gain (Loss) on Risk Management Contracts $ 5,424 $ 853 $ (23,436 ) $ (894 ) $ 1,103 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,231 $ 2,988 $ 41 $ 45 $ 74 Sales to AEP Affiliates — (196 ) — 196 — Regulatory Assets (a) (2,571 ) (471 ) (852 ) (109 ) (284 ) Regulatory Liabilities (a) (3,606 ) (176 ) (1,555 ) 120 (180 ) Total Gain (Loss) on Risk Management Contracts $ (4,946 ) $ 2,145 $ (2,366 ) $ 252 $ (390 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 790 $ 3,591 $ (882 ) $ 16 $ 19 Sales to AEP Affiliates 1,511 4,341 — — — Other Operation Expense (287 ) (221 ) (389 ) (307 ) (373 ) Maintenance Expense (503 ) (221 ) (396 ) (248 ) (265 ) Purchased Electricity for Resale 1,571 347 30 — — Regulatory Assets (a) 2,136 (1,213 ) — 615 (1,234 ) Regulatory Liabilities (a) 31,797 4,121 (24,880 ) 5,076 14,446 Total Gain (Loss) on Risk Management Contracts $ 37,015 $ 10,745 $ (26,517 ) $ 5,152 $ 12,593 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 7,262 $ 10,467 $ 97 $ 172 $ 18 Sales to AEP Affiliates — (717 ) — 717 — Regulatory Assets (a) (2,567 ) (471 ) (215 ) (119 ) (285 ) Regulatory Liabilities (a) 42,444 26,934 39,311 (69 ) 119 Total Gain (Loss) on Risk Management Contracts $ 47,139 $ 36,213 $ 39,193 $ 701 $ (148 ) (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2015 , the Registrant Subsidiaries did not designate power derivatives as cash flow hedges. During the three and nine months ended September 30, 2014 , APCo and I&M designated power derivatives as cash flow hedges. The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. The impact of cash flow hedge accounting for these derivative contracts was immaterial and was discontinued effective March 31, 2014. The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2015 and 2014 , the Registrant Subsidiaries did not designate interest rate derivatives as cash flow hedges. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2015 and 2014 , the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and nine months ended September 30, 2015 and 2014 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2015 and 2014 , see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2015 and December 31, 2014 were: Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets September 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,805 I&M — — — — — (13,604 ) OPCo — — — — — 4,572 PSO — — — — — 4,374 SWEPCo — — — — — (9,470 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 734 0 I&M — (1,277 ) 0 OPCo — 1,282 0 PSO — 771 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. Credit Risk AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate g |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2015 | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For our commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated. We typically obtain multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, we average the quoted bid and ask prices. In certain circumstances, we may discard a broker quote if it is a clear outlier. We use a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, we include these locations within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of our contracts being classified as Level 3 is the inability to substantiate our energy price curves in the market. A significant portion of our Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. We utilize our trustee’s external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts. Our investment managers review and validate the prices utilized by the trustee to determine fair value. We perform our own valuation testing to verify the fair values of the securities. We receive audit reports of our trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange. The book values and fair values of Long-term Debt as of September 30, 2015 and December 31, 2014 are summarized in the following table: September 30, 2015 December 31, 2014 Book Value (a) Fair Value Book Value (a) Fair Value (in millions) Long-term Debt $ 19,507 $ 21,257 $ 18,684 $ 21,075 (a) Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that we intend to hold for less than one year and investments by our protected cell of EIS. The following is a summary of Other Temporary Investments: September 30, 2015 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 201 $ — $ — $ 201 Fixed Income Securities – Mutual Funds 90 — — 90 Equity Securities – Mutual Funds 14 10 — 24 Total Other Temporary Investments $ 305 $ 10 $ — $ 315 December 31, 2014 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 280 $ — $ — $ 280 Fixed Income Securities – Mutual Funds 81 — — 81 Equity Securities – Mutual Funds 13 12 — 25 Total Other Temporary Investments $ 374 $ 12 $ — $ 386 (a) Primarily represents amounts held for the repayment of debt. The following table provides the activity for our fixed income and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2015 and 2014 : Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 10 — 10 1 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — As of September 30, 2015 and December 31, 2014 , we had no Other Temporary Investments with an unrealized loss position. As of September 30, 2015 , fixed income securities were primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates. For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP or its affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. We maintain trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in the trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. The following is a summary of nuclear trust fund investments as of September 30, 2015 and December 31, 2014 : September 30, 2015 December 31, 2014 Fair Value Gross Unrealized Gains Other-Than- Temporary Fair Value Gross Unrealized Gains Other-Than- Temporary (in millions) Cash and Cash Equivalents $ 164 $ — $ — $ 20 $ — $ — Fixed Income Securities: United States Government 704 45 (2 ) 697 45 (5 ) Corporate Debt 62 4 (1 ) 48 4 (1 ) State and Local Government 50 1 — 208 1 — Subtotal Fixed Income Securities 816 50 (3 ) 953 50 (6 ) Equity Securities – Domestic 1,067 516 (80 ) 1,123 599 (79 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,047 $ 566 $ (83 ) $ 2,096 $ 649 $ (85 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2015 and 2014 : Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in millions) Proceeds from Investment Sales $ 921 $ 263 $ 1,437 $ 746 Purchases of Investments 938 281 1,479 790 Gross Realized Gains on Investment Sales 15 8 34 25 Gross Realized Losses on Investment Sales 13 1 23 10 The adjusted cost of fixed income securities was $766 million and $903 million as of September 30, 2015 and December 31, 2014 , respectively. The adjusted cost of equity securities was $551 million and $524 million as of September 30, 2015 and December 31, 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2015 was as follows: Fair Value of Securities (in millions) Within 1 year $ 166 1 year – 5 years 336 5 years – 10 years 140 After 10 years 174 Total $ 816 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in our valuation techniques. Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12 $ 4 $ — $ 162 $ 178 Other Temporary Investments Restricted Cash (a) 189 6 — 6 201 Fixed Income Securities - Mutual Funds 90 — — — 90 Equity Securities – Mutual Funds (b) 24 — — — 24 Total Other Temporary Investments 303 6 — 6 315 Risk Management Assets Risk Management Commodity Contracts (c) (d) 17 478 248 (256 ) 487 Cash Flow Hedges: Commodity Hedges (c) — 10 1 (4 ) 7 Fair Value Hedges — 1 — 1 2 Total Risk Management Assets 17 489 249 (259 ) 496 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 157 — — 7 164 Fixed Income Securities: United States Government — 704 — — 704 Corporate Debt — 62 — — 62 State and Local Government — 50 — — 50 Subtotal Fixed Income Securities — 816 — — 816 Equity Securities – Domestic (b) 1,067 — — — 1,067 Total Spent Nuclear Fuel and Decommissioning Trusts 1,224 816 — 7 2,047 Total Assets $ 1,556 $ 1,315 $ 249 $ (84 ) $ 3,036 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 33 $ 440 $ 76 $ (299 ) $ 250 Cash Flow Hedges: Commodity Hedges (c) — 22 6 (4 ) 24 Interest Rate/Foreign Currency Hedges — 1 — — 1 Fair Value Hedges — — — 1 1 Total Risk Management Liabilities $ 33 $ 463 $ 82 $ (302 ) $ 276 Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17 $ 1 $ — $ 145 $ 163 Other Temporary Investments Restricted Cash (a) 234 9 — 37 280 Fixed Income Securities - Mutual Funds 81 — — — 81 Equity Securities – Mutual Funds (b) 25 — — — 25 Total Other Temporary Investments 340 9 — 37 386 Risk Management Assets Risk Management Commodity Contracts (c) (f) 37 528 190 (302 ) 453 Cash Flow Hedges: Commodity Hedges (c) — 32 — (16 ) 16 Fair Value Hedges — 1 — 2 3 Total Risk Management Assets 37 561 190 (316 ) 472 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9 — — 11 20 Fixed Income Securities: United States Government — 697 — — 697 Corporate Debt — 48 — — 48 State and Local Government — 208 — — 208 Subtotal Fixed Income Securities — 953 — — 953 Equity Securities – Domestic (b) 1,123 — — — 1,123 Total Spent Nuclear Fuel and Decommissioning Trusts 1,132 953 — 11 2,096 Total Assets $ 1,526 $ 1,524 $ 190 $ (123 ) $ 3,117 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 65 $ 432 $ 36 $ (334 ) $ 199 Cash Flow Hedges: Commodity Hedges (c) — 27 3 (16 ) 14 Interest Rate/Foreign Currency Hedges — 1 — — 1 Fair Value Hedges — 7 — 2 9 Total Risk Management Liabilities $ 65 $ 467 $ 39 $ (348 ) $ 223 (a) Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.'' (d) The September 30, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($4) million in 2015 and ($12) million in periods 2016-2018; Level 2 matures $5 million in 2015 , $28 million in periods 2016-2018, $3 million in periods 2019-2020 and $2 million in periods 2021-2032; Level 3 matures $2 million in 2015 , $63 million in periods 2016-2018, $25 million in periods 2019-2020 and $82 million in periods 2021-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $31 million in 2015 , $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015 , $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as Level 3 in the fair value hierarchy: Three Months Ended September 30, 2015 Net Risk Management Assets (Liabilities) (in millions) Balance as of June 30, 2015 $ 203 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 11 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 6 Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2 ) Purchases, Issuances and Settlements (c) (29 ) Transfers into Level 3 (d) (e) 8 Transfers out of Level 3 (e) (f) (5 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) (25 ) Balance as of September 30, 2015 $ 167 Three Months Ended September 30, 2014 Net Risk Management (in millions) Balance as of June 30, 2014 $ 132 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (9 ) Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 10 Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3 ) Purchases, Issuances and Settlements (c) (5 ) Transfers into Level 3 (d) (e) (9 ) Transfers out of Level 3 (e) (f) (1 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14 Balance as of September 30, 2014 $ 129 Nine Months Ended September 30, 2015 Net Risk Management (in millions) Balance as of December 31, 2014 $ 151 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 14 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 54 Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4 ) Purchases, Issuances and Settlements (c) (60 ) Transfers into Level 3 (d) (e) 28 Transfers out of Level 3 (e) (f) (17 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 1 Balance as of September 30, 2015 $ 167 Nine Months Ended September 30, 2014 Net Risk Management (in millions) Balance as of December 31, 2013 $ 117 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 91 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (3 ) Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12 Purchases, Issuances and Settlements (c) (103 ) Transfers into Level 3 (d) (e) (9 ) Transfers out of Level 3 (e) (f) (8 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 32 Balance as of September 30, 2014 $ 129 (a) Included in revenues on the condensed statements of income. (b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (c) Represents the settlement of risk management commodity contracts for the reporting period. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Represents existing assets or liabilities that were previously categorized as Level 3. (g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. The following tables quantify the significant unobservable inputs used in developing the fair value of our Level 3 positions as of September 30, 2015 and December 31, 2014 : Significant Unobservable Inputs September 30, 2015 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 226 $ 79 Discounted Cash Flow Forward Market Price (a) $ 13.03 $ 165.93 $ 36.37 Counterparty Credit Risk (b) 481 FTRs 23 3 Discounted Cash Flow Forward Market Price (a) (10.67 ) 11.60 1.31 Total $ 249 $ 82 Significant Unobservable Inputs December 31, 2014 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157 $ 37 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33 2 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190 $ 39 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs as of September 30, 2015 : Sensitivity of Fair Value Measurements September 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher) |
Appalachian Power Co [Member] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of September 30, 2015 and December 31, 2014 are summarized in the following table: September 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,955,295 $ 4,460,140 $ 3,980,274 $ 4,711,210 I&M 2,060,651 2,241,930 2,027,397 2,255,124 OPCo 2,166,050 2,502,105 2,297,123 2,709,452 PSO 1,290,973 1,424,300 1,041,036 1,216,205 SWEPCo 2,283,966 2,446,716 2,140,437 2,402,639 Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP or its affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. The following is a summary of nuclear trust fund investments as of September 30, 2015 and December 31, 2014 : September 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 164,353 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 704,344 45,005 (2,291 ) 697,042 44,615 (5,016 ) Corporate Debt 62,118 3,682 (1,043 ) 47,792 4,523 (1,018 ) State and Local Government 50,018 996 (324 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 816,480 49,683 (3,658 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,066,427 516,206 (80,280 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,047,260 $ 565,889 $ (83,938 ) $ 2,095,732 $ 649,132 $ (85,495 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2015 and 2014 : Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 921,552 $ 263,738 $ 1,437,336 $ 746,272 Purchases of Investments 938,438 280,626 1,479,149 789,461 Gross Realized Gains on Investment Sales 15,030 7,617 33,840 24,835 Gross Realized Losses on Investment Sales 13,167 1,739 22,823 10,447 The adjusted cost of fixed income securities was $766 million and $903 million as of September 30, 2015 and December 31, 2014 , respectively. The adjusted cost of equity securities was $551 million and $524 million as of September 30, 2015 and December 31, 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2015 was as follows: Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 166,336 1 year – 5 years 335,823 5 years – 10 years 140,129 After 10 years 174,192 Total $ 816,480 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 7,436 $ — $ — $ 57 $ 7,493 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) 185 12,785 23,743 (7,328 ) 29,385 Total Assets: $ 7,621 $ 12,785 $ 23,743 $ (7,271 ) $ 36,878 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 198 $ 16,031 $ 662 $ (9,016 ) $ 7,875 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) $ 126 $ 10,347 $ 7,795 $ (6,303 ) $ 11,965 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 157,409 — — 6,944 164,353 Fixed Income Securities: United States Government — 704,344 — — 704,344 Corporate Debt — 62,118 — — 62,118 State and Local Government — 50,018 — — 50,018 Subtotal Fixed Income Securities — 816,480 — — 816,480 Equity Securities - Domestic (e) 1,066,427 — — — 1,066,427 Total Spent Nuclear Fuel and Decommissioning Trusts 1,223,836 816,480 — 6,944 2,047,260 Total Assets $ 1,223,962 $ 826,827 $ 7,795 $ 641 $ 2,059,225 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 135 $ 10,945 $ 1,419 $ (6,636 ) $ 5,863 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 16,195 $ — $ — $ 9 $ 16,204 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 20,719 2,546 23,265 Total Assets $ 16,195 $ — $ 20,719 $ 2,555 $ 39,469 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 639 $ 5,009 $ 2,046 $ 7,694 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 1,166 $ (131 ) $ 1,035 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 358 $ 131 $ (411 ) $ 78 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 11,688 $ — $ — $ 2,570 $ 14,258 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 1,442 (162 ) 1,280 Total Assets $ 11,688 $ — $ 1,442 $ 2,408 $ 15,538 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 2,378 $ 162 $ (481 ) $ 2,059 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. (d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (e) Amounts represent publicly traded equity securities and equity-based mutual funds. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy for the Registrant Subsidiaries: Three Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 5,065 885 (28 ) (280 ) 2,366 Purchases, Issuances and Settlements (d) (13,965 ) (3,604 ) 348 (176 ) (2,912 ) Changes in Fair Value Allocated to Regulated Jurisdictions (h) (1,855 ) (2,749 ) (22,267 ) (208 ) (213 ) Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Three Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (5,629 ) (3,832 ) (3,639 ) 2 2 Purchases, Issuances and Settlements (d) (1,560 ) (1,244 ) (637 ) — — Transfers into Level 3 (e) (f) (6 ) (4 ) — — — Transfers out of Level 3 (f) (g) (30 ) (20 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 4,843 4,319 2,865 335 409 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 Nine Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 1,757 (193 ) 1,182 (176 ) 9,187 Purchases, Issuances and Settlements (d) (16,124 ) (12,807 ) (7,906 ) 553 (8,727 ) Transfers out of Level 3 (f) (g) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 20,539 3,880 (25,968 ) 1,035 1,280 Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Nine Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2013 $ 10,562 $ 7,164 $ 2,920 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 29,467 18,438 30,768 — — Purchases, Issuances and Settlements (d) (32,213 ) (20,301 ) (33,688 ) — — Transfers into Level 3 (e) (f) (3,648 ) (2,475 ) — — — Transfers out of Level 3 (f) (g) (32 ) (22 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 11,876 9,338 7,889 334 408 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the condensed statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions for the Registrant Subsidiaries as of September 30, 2015 and December 31, 2014 : Significant Unobservable Inputs September 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 8,724 $ 451 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 15,019 211 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 23,743 $ 662 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs September 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 7,147 $ 295 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 648 1,124 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 7,795 $ 1,419 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs September 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 20,719 $ 5,009 Discounted Cash Flow Forward Market Price $ 35.71 $ 165.93 $ 85.99 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52,343 $ 3,941 Significant Unobservable Inputs September 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,166 $ 131 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs September 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,442 $ 162 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant Subsidiaries as of September 30, 2015 : Sensitivity of Fair Value Measurements September 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) |
Indiana Michigan Power Co [Member] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of September 30, 2015 and December 31, 2014 are summarized in the following table: September 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,955,295 $ 4,460,140 $ 3,980,274 $ 4,711,210 I&M 2,060,651 2,241,930 2,027,397 2,255,124 OPCo 2,166,050 2,502,105 2,297,123 2,709,452 PSO 1,290,973 1,424,300 1,041,036 1,216,205 SWEPCo 2,283,966 2,446,716 2,140,437 2,402,639 Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP or its affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. The following is a summary of nuclear trust fund investments as of September 30, 2015 and December 31, 2014 : September 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 164,353 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 704,344 45,005 (2,291 ) 697,042 44,615 (5,016 ) Corporate Debt 62,118 3,682 (1,043 ) 47,792 4,523 (1,018 ) State and Local Government 50,018 996 (324 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 816,480 49,683 (3,658 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,066,427 516,206 (80,280 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,047,260 $ 565,889 $ (83,938 ) $ 2,095,732 $ 649,132 $ (85,495 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2015 and 2014 : Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 921,552 $ 263,738 $ 1,437,336 $ 746,272 Purchases of Investments 938,438 280,626 1,479,149 789,461 Gross Realized Gains on Investment Sales 15,030 7,617 33,840 24,835 Gross Realized Losses on Investment Sales 13,167 1,739 22,823 10,447 The adjusted cost of fixed income securities was $766 million and $903 million as of September 30, 2015 and December 31, 2014 , respectively. The adjusted cost of equity securities was $551 million and $524 million as of September 30, 2015 and December 31, 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2015 was as follows: Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 166,336 1 year – 5 years 335,823 5 years – 10 years 140,129 After 10 years 174,192 Total $ 816,480 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 7,436 $ — $ — $ 57 $ 7,493 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) 185 12,785 23,743 (7,328 ) 29,385 Total Assets: $ 7,621 $ 12,785 $ 23,743 $ (7,271 ) $ 36,878 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 198 $ 16,031 $ 662 $ (9,016 ) $ 7,875 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) $ 126 $ 10,347 $ 7,795 $ (6,303 ) $ 11,965 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 157,409 — — 6,944 164,353 Fixed Income Securities: United States Government — 704,344 — — 704,344 Corporate Debt — 62,118 — — 62,118 State and Local Government — 50,018 — — 50,018 Subtotal Fixed Income Securities — 816,480 — — 816,480 Equity Securities - Domestic (e) 1,066,427 — — — 1,066,427 Total Spent Nuclear Fuel and Decommissioning Trusts 1,223,836 816,480 — 6,944 2,047,260 Total Assets $ 1,223,962 $ 826,827 $ 7,795 $ 641 $ 2,059,225 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 135 $ 10,945 $ 1,419 $ (6,636 ) $ 5,863 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 16,195 $ — $ — $ 9 $ 16,204 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 20,719 2,546 23,265 Total Assets $ 16,195 $ — $ 20,719 $ 2,555 $ 39,469 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 639 $ 5,009 $ 2,046 $ 7,694 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 1,166 $ (131 ) $ 1,035 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 358 $ 131 $ (411 ) $ 78 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 11,688 $ — $ — $ 2,570 $ 14,258 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 1,442 (162 ) 1,280 Total Assets $ 11,688 $ — $ 1,442 $ 2,408 $ 15,538 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 2,378 $ 162 $ (481 ) $ 2,059 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. (d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (e) Amounts represent publicly traded equity securities and equity-based mutual funds. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy for the Registrant Subsidiaries: Three Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 5,065 885 (28 ) (280 ) 2,366 Purchases, Issuances and Settlements (d) (13,965 ) (3,604 ) 348 (176 ) (2,912 ) Changes in Fair Value Allocated to Regulated Jurisdictions (h) (1,855 ) (2,749 ) (22,267 ) (208 ) (213 ) Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Three Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (5,629 ) (3,832 ) (3,639 ) 2 2 Purchases, Issuances and Settlements (d) (1,560 ) (1,244 ) (637 ) — — Transfers into Level 3 (e) (f) (6 ) (4 ) — — — Transfers out of Level 3 (f) (g) (30 ) (20 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 4,843 4,319 2,865 335 409 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 Nine Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 1,757 (193 ) 1,182 (176 ) 9,187 Purchases, Issuances and Settlements (d) (16,124 ) (12,807 ) (7,906 ) 553 (8,727 ) Transfers out of Level 3 (f) (g) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 20,539 3,880 (25,968 ) 1,035 1,280 Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Nine Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2013 $ 10,562 $ 7,164 $ 2,920 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 29,467 18,438 30,768 — — Purchases, Issuances and Settlements (d) (32,213 ) (20,301 ) (33,688 ) — — Transfers into Level 3 (e) (f) (3,648 ) (2,475 ) — — — Transfers out of Level 3 (f) (g) (32 ) (22 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 11,876 9,338 7,889 334 408 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the condensed statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions for the Registrant Subsidiaries as of September 30, 2015 and December 31, 2014 : Significant Unobservable Inputs September 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 8,724 $ 451 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 15,019 211 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 23,743 $ 662 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs September 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 7,147 $ 295 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 648 1,124 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 7,795 $ 1,419 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs September 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 20,719 $ 5,009 Discounted Cash Flow Forward Market Price $ 35.71 $ 165.93 $ 85.99 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52,343 $ 3,941 Significant Unobservable Inputs September 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,166 $ 131 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs September 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,442 $ 162 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant Subsidiaries as of September 30, 2015 : Sensitivity of Fair Value Measurements September 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) |
Ohio Power Co [Member] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of September 30, 2015 and December 31, 2014 are summarized in the following table: September 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,955,295 $ 4,460,140 $ 3,980,274 $ 4,711,210 I&M 2,060,651 2,241,930 2,027,397 2,255,124 OPCo 2,166,050 2,502,105 2,297,123 2,709,452 PSO 1,290,973 1,424,300 1,041,036 1,216,205 SWEPCo 2,283,966 2,446,716 2,140,437 2,402,639 Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP or its affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. The following is a summary of nuclear trust fund investments as of September 30, 2015 and December 31, 2014 : September 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 164,353 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 704,344 45,005 (2,291 ) 697,042 44,615 (5,016 ) Corporate Debt 62,118 3,682 (1,043 ) 47,792 4,523 (1,018 ) State and Local Government 50,018 996 (324 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 816,480 49,683 (3,658 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,066,427 516,206 (80,280 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,047,260 $ 565,889 $ (83,938 ) $ 2,095,732 $ 649,132 $ (85,495 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2015 and 2014 : Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 921,552 $ 263,738 $ 1,437,336 $ 746,272 Purchases of Investments 938,438 280,626 1,479,149 789,461 Gross Realized Gains on Investment Sales 15,030 7,617 33,840 24,835 Gross Realized Losses on Investment Sales 13,167 1,739 22,823 10,447 The adjusted cost of fixed income securities was $766 million and $903 million as of September 30, 2015 and December 31, 2014 , respectively. The adjusted cost of equity securities was $551 million and $524 million as of September 30, 2015 and December 31, 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2015 was as follows: Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 166,336 1 year – 5 years 335,823 5 years – 10 years 140,129 After 10 years 174,192 Total $ 816,480 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 7,436 $ — $ — $ 57 $ 7,493 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) 185 12,785 23,743 (7,328 ) 29,385 Total Assets: $ 7,621 $ 12,785 $ 23,743 $ (7,271 ) $ 36,878 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 198 $ 16,031 $ 662 $ (9,016 ) $ 7,875 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) $ 126 $ 10,347 $ 7,795 $ (6,303 ) $ 11,965 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 157,409 — — 6,944 164,353 Fixed Income Securities: United States Government — 704,344 — — 704,344 Corporate Debt — 62,118 — — 62,118 State and Local Government — 50,018 — — 50,018 Subtotal Fixed Income Securities — 816,480 — — 816,480 Equity Securities - Domestic (e) 1,066,427 — — — 1,066,427 Total Spent Nuclear Fuel and Decommissioning Trusts 1,223,836 816,480 — 6,944 2,047,260 Total Assets $ 1,223,962 $ 826,827 $ 7,795 $ 641 $ 2,059,225 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 135 $ 10,945 $ 1,419 $ (6,636 ) $ 5,863 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 16,195 $ — $ — $ 9 $ 16,204 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 20,719 2,546 23,265 Total Assets $ 16,195 $ — $ 20,719 $ 2,555 $ 39,469 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 639 $ 5,009 $ 2,046 $ 7,694 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 1,166 $ (131 ) $ 1,035 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 358 $ 131 $ (411 ) $ 78 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 11,688 $ — $ — $ 2,570 $ 14,258 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 1,442 (162 ) 1,280 Total Assets $ 11,688 $ — $ 1,442 $ 2,408 $ 15,538 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 2,378 $ 162 $ (481 ) $ 2,059 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. (d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (e) Amounts represent publicly traded equity securities and equity-based mutual funds. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy for the Registrant Subsidiaries: Three Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 5,065 885 (28 ) (280 ) 2,366 Purchases, Issuances and Settlements (d) (13,965 ) (3,604 ) 348 (176 ) (2,912 ) Changes in Fair Value Allocated to Regulated Jurisdictions (h) (1,855 ) (2,749 ) (22,267 ) (208 ) (213 ) Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Three Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (5,629 ) (3,832 ) (3,639 ) 2 2 Purchases, Issuances and Settlements (d) (1,560 ) (1,244 ) (637 ) — — Transfers into Level 3 (e) (f) (6 ) (4 ) — — — Transfers out of Level 3 (f) (g) (30 ) (20 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 4,843 4,319 2,865 335 409 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 Nine Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 1,757 (193 ) 1,182 (176 ) 9,187 Purchases, Issuances and Settlements (d) (16,124 ) (12,807 ) (7,906 ) 553 (8,727 ) Transfers out of Level 3 (f) (g) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 20,539 3,880 (25,968 ) 1,035 1,280 Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Nine Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2013 $ 10,562 $ 7,164 $ 2,920 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 29,467 18,438 30,768 — — Purchases, Issuances and Settlements (d) (32,213 ) (20,301 ) (33,688 ) — — Transfers into Level 3 (e) (f) (3,648 ) (2,475 ) — — — Transfers out of Level 3 (f) (g) (32 ) (22 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 11,876 9,338 7,889 334 408 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the condensed statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions for the Registrant Subsidiaries as of September 30, 2015 and December 31, 2014 : Significant Unobservable Inputs September 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 8,724 $ 451 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 15,019 211 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 23,743 $ 662 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs September 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 7,147 $ 295 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 648 1,124 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 7,795 $ 1,419 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs September 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 20,719 $ 5,009 Discounted Cash Flow Forward Market Price $ 35.71 $ 165.93 $ 85.99 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52,343 $ 3,941 Significant Unobservable Inputs September 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,166 $ 131 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs September 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,442 $ 162 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant Subsidiaries as of September 30, 2015 : Sensitivity of Fair Value Measurements September 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) |
Public Service Co Of Oklahoma [Member] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of September 30, 2015 and December 31, 2014 are summarized in the following table: September 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,955,295 $ 4,460,140 $ 3,980,274 $ 4,711,210 I&M 2,060,651 2,241,930 2,027,397 2,255,124 OPCo 2,166,050 2,502,105 2,297,123 2,709,452 PSO 1,290,973 1,424,300 1,041,036 1,216,205 SWEPCo 2,283,966 2,446,716 2,140,437 2,402,639 Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP or its affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. The following is a summary of nuclear trust fund investments as of September 30, 2015 and December 31, 2014 : September 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 164,353 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 704,344 45,005 (2,291 ) 697,042 44,615 (5,016 ) Corporate Debt 62,118 3,682 (1,043 ) 47,792 4,523 (1,018 ) State and Local Government 50,018 996 (324 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 816,480 49,683 (3,658 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,066,427 516,206 (80,280 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,047,260 $ 565,889 $ (83,938 ) $ 2,095,732 $ 649,132 $ (85,495 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2015 and 2014 : Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 921,552 $ 263,738 $ 1,437,336 $ 746,272 Purchases of Investments 938,438 280,626 1,479,149 789,461 Gross Realized Gains on Investment Sales 15,030 7,617 33,840 24,835 Gross Realized Losses on Investment Sales 13,167 1,739 22,823 10,447 The adjusted cost of fixed income securities was $766 million and $903 million as of September 30, 2015 and December 31, 2014 , respectively. The adjusted cost of equity securities was $551 million and $524 million as of September 30, 2015 and December 31, 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2015 was as follows: Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 166,336 1 year – 5 years 335,823 5 years – 10 years 140,129 After 10 years 174,192 Total $ 816,480 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 7,436 $ — $ — $ 57 $ 7,493 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) 185 12,785 23,743 (7,328 ) 29,385 Total Assets: $ 7,621 $ 12,785 $ 23,743 $ (7,271 ) $ 36,878 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 198 $ 16,031 $ 662 $ (9,016 ) $ 7,875 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) $ 126 $ 10,347 $ 7,795 $ (6,303 ) $ 11,965 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 157,409 — — 6,944 164,353 Fixed Income Securities: United States Government — 704,344 — — 704,344 Corporate Debt — 62,118 — — 62,118 State and Local Government — 50,018 — — 50,018 Subtotal Fixed Income Securities — 816,480 — — 816,480 Equity Securities - Domestic (e) 1,066,427 — — — 1,066,427 Total Spent Nuclear Fuel and Decommissioning Trusts 1,223,836 816,480 — 6,944 2,047,260 Total Assets $ 1,223,962 $ 826,827 $ 7,795 $ 641 $ 2,059,225 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 135 $ 10,945 $ 1,419 $ (6,636 ) $ 5,863 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 16,195 $ — $ — $ 9 $ 16,204 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 20,719 2,546 23,265 Total Assets $ 16,195 $ — $ 20,719 $ 2,555 $ 39,469 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 639 $ 5,009 $ 2,046 $ 7,694 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 1,166 $ (131 ) $ 1,035 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 358 $ 131 $ (411 ) $ 78 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 11,688 $ — $ — $ 2,570 $ 14,258 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 1,442 (162 ) 1,280 Total Assets $ 11,688 $ — $ 1,442 $ 2,408 $ 15,538 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 2,378 $ 162 $ (481 ) $ 2,059 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. (d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (e) Amounts represent publicly traded equity securities and equity-based mutual funds. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy for the Registrant Subsidiaries: Three Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 5,065 885 (28 ) (280 ) 2,366 Purchases, Issuances and Settlements (d) (13,965 ) (3,604 ) 348 (176 ) (2,912 ) Changes in Fair Value Allocated to Regulated Jurisdictions (h) (1,855 ) (2,749 ) (22,267 ) (208 ) (213 ) Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Three Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (5,629 ) (3,832 ) (3,639 ) 2 2 Purchases, Issuances and Settlements (d) (1,560 ) (1,244 ) (637 ) — — Transfers into Level 3 (e) (f) (6 ) (4 ) — — — Transfers out of Level 3 (f) (g) (30 ) (20 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 4,843 4,319 2,865 335 409 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 Nine Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 1,757 (193 ) 1,182 (176 ) 9,187 Purchases, Issuances and Settlements (d) (16,124 ) (12,807 ) (7,906 ) 553 (8,727 ) Transfers out of Level 3 (f) (g) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 20,539 3,880 (25,968 ) 1,035 1,280 Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Nine Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2013 $ 10,562 $ 7,164 $ 2,920 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 29,467 18,438 30,768 — — Purchases, Issuances and Settlements (d) (32,213 ) (20,301 ) (33,688 ) — — Transfers into Level 3 (e) (f) (3,648 ) (2,475 ) — — — Transfers out of Level 3 (f) (g) (32 ) (22 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 11,876 9,338 7,889 334 408 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the condensed statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions for the Registrant Subsidiaries as of September 30, 2015 and December 31, 2014 : Significant Unobservable Inputs September 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 8,724 $ 451 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 15,019 211 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 23,743 $ 662 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs September 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 7,147 $ 295 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 648 1,124 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 7,795 $ 1,419 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs September 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 20,719 $ 5,009 Discounted Cash Flow Forward Market Price $ 35.71 $ 165.93 $ 85.99 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52,343 $ 3,941 Significant Unobservable Inputs September 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,166 $ 131 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs September 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,442 $ 162 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant Subsidiaries as of September 30, 2015 : Sensitivity of Fair Value Measurements September 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) |
Southwestern Electric Power Co [Member] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of September 30, 2015 and December 31, 2014 are summarized in the following table: September 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,955,295 $ 4,460,140 $ 3,980,274 $ 4,711,210 I&M 2,060,651 2,241,930 2,027,397 2,255,124 OPCo 2,166,050 2,502,105 2,297,123 2,709,452 PSO 1,290,973 1,424,300 1,041,036 1,216,205 SWEPCo 2,283,966 2,446,716 2,140,437 2,402,639 Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP or its affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. The following is a summary of nuclear trust fund investments as of September 30, 2015 and December 31, 2014 : September 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 164,353 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 704,344 45,005 (2,291 ) 697,042 44,615 (5,016 ) Corporate Debt 62,118 3,682 (1,043 ) 47,792 4,523 (1,018 ) State and Local Government 50,018 996 (324 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 816,480 49,683 (3,658 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,066,427 516,206 (80,280 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,047,260 $ 565,889 $ (83,938 ) $ 2,095,732 $ 649,132 $ (85,495 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2015 and 2014 : Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 921,552 $ 263,738 $ 1,437,336 $ 746,272 Purchases of Investments 938,438 280,626 1,479,149 789,461 Gross Realized Gains on Investment Sales 15,030 7,617 33,840 24,835 Gross Realized Losses on Investment Sales 13,167 1,739 22,823 10,447 The adjusted cost of fixed income securities was $766 million and $903 million as of September 30, 2015 and December 31, 2014 , respectively. The adjusted cost of equity securities was $551 million and $524 million as of September 30, 2015 and December 31, 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2015 was as follows: Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 166,336 1 year – 5 years 335,823 5 years – 10 years 140,129 After 10 years 174,192 Total $ 816,480 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 7,436 $ — $ — $ 57 $ 7,493 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) 185 12,785 23,743 (7,328 ) 29,385 Total Assets: $ 7,621 $ 12,785 $ 23,743 $ (7,271 ) $ 36,878 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 198 $ 16,031 $ 662 $ (9,016 ) $ 7,875 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) $ 126 $ 10,347 $ 7,795 $ (6,303 ) $ 11,965 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 157,409 — — 6,944 164,353 Fixed Income Securities: United States Government — 704,344 — — 704,344 Corporate Debt — 62,118 — — 62,118 State and Local Government — 50,018 — — 50,018 Subtotal Fixed Income Securities — 816,480 — — 816,480 Equity Securities - Domestic (e) 1,066,427 — — — 1,066,427 Total Spent Nuclear Fuel and Decommissioning Trusts 1,223,836 816,480 — 6,944 2,047,260 Total Assets $ 1,223,962 $ 826,827 $ 7,795 $ 641 $ 2,059,225 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 135 $ 10,945 $ 1,419 $ (6,636 ) $ 5,863 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 16,195 $ — $ — $ 9 $ 16,204 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 20,719 2,546 23,265 Total Assets $ 16,195 $ — $ 20,719 $ 2,555 $ 39,469 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 639 $ 5,009 $ 2,046 $ 7,694 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 1,166 $ (131 ) $ 1,035 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 358 $ 131 $ (411 ) $ 78 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 11,688 $ — $ — $ 2,570 $ 14,258 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 1,442 (162 ) 1,280 Total Assets $ 11,688 $ — $ 1,442 $ 2,408 $ 15,538 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 2,378 $ 162 $ (481 ) $ 2,059 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. (d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (e) Amounts represent publicly traded equity securities and equity-based mutual funds. There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy for the Registrant Subsidiaries: Three Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 5,065 885 (28 ) (280 ) 2,366 Purchases, Issuances and Settlements (d) (13,965 ) (3,604 ) 348 (176 ) (2,912 ) Changes in Fair Value Allocated to Regulated Jurisdictions (h) (1,855 ) (2,749 ) (22,267 ) (208 ) (213 ) Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Three Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (5,629 ) (3,832 ) (3,639 ) 2 2 Purchases, Issuances and Settlements (d) (1,560 ) (1,244 ) (637 ) — — Transfers into Level 3 (e) (f) (6 ) (4 ) — — — Transfers out of Level 3 (f) (g) (30 ) (20 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 4,843 4,319 2,865 335 409 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 Nine Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 1,757 (193 ) 1,182 (176 ) 9,187 Purchases, Issuances and Settlements (d) (16,124 ) (12,807 ) (7,906 ) 553 (8,727 ) Transfers out of Level 3 (f) (g) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 20,539 3,880 (25,968 ) 1,035 1,280 Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Nine Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2013 $ 10,562 $ 7,164 $ 2,920 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 29,467 18,438 30,768 — — Purchases, Issuances and Settlements (d) (32,213 ) (20,301 ) (33,688 ) — — Transfers into Level 3 (e) (f) (3,648 ) (2,475 ) — — — Transfers out of Level 3 (f) (g) (32 ) (22 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 11,876 9,338 7,889 334 408 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the condensed statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions for the Registrant Subsidiaries as of September 30, 2015 and December 31, 2014 : Significant Unobservable Inputs September 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 8,724 $ 451 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 15,019 211 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 23,743 $ 662 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs September 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 7,147 $ 295 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 648 1,124 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 7,795 $ 1,419 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs September 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 20,719 $ 5,009 Discounted Cash Flow Forward Market Price $ 35.71 $ 165.93 $ 85.99 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52,343 $ 3,941 Significant Unobservable Inputs September 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,166 $ 131 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs September 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,442 $ 162 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant Subsidiaries as of September 30, 2015 : Sensitivity of Fair Value Measurements September 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2015 | |
Income Taxes | INCOME TAXES AEP System Tax Allocation Agreement We, along with our subsidiaries, file a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance We assess the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to use existing deferred tax assets. On the basis of this evaluation, we recorded a valuation allowance of $165 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of our investment in the operations of AEPRO. The assets and liabilities of AEPRO have been recorded as Assets Held for Sale and Liabilities Held for Sale, respectively, on our condensed balance sheets as of September 30, 2015 and December 31, 2014. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information regarding the assets and liabilities classified as held for sale. As of September 30, 2015, valuation allowances totaling $221 million for unrealized capital losses have been recorded in order to recognize only the portion of the deferred tax assets that, more likely than not, will be realized. Federal and State Income Tax Audit Status We are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in our opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, we accrue interest on these uncertain tax positions. We are not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine our tax returns. We are currently under examination in several state and local jurisdictions. However, it is possible that we have filed tax returns with positions that may be challenged by these tax authorities. We believe that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. We are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact net income, cash flows or financial condition. |
Appalachian Power Co [Member] | |
Income Taxes | INCOME TAXES AEP System Tax Allocation Agreement The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Federal and State Income Tax Audit Status The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact the Registrant Subsidiaries' net income. The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact the Registrant Subsidiaries' net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. State Tax Legislation House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrant Subsidiaries' net income, cash flows or financial condition. |
Indiana Michigan Power Co [Member] | |
Income Taxes | INCOME TAXES AEP System Tax Allocation Agreement The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Federal and State Income Tax Audit Status The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact the Registrant Subsidiaries' net income. The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact the Registrant Subsidiaries' net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. State Tax Legislation House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrant Subsidiaries' net income, cash flows or financial condition. |
Ohio Power Co [Member] | |
Income Taxes | INCOME TAXES AEP System Tax Allocation Agreement The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Federal and State Income Tax Audit Status The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact the Registrant Subsidiaries' net income. The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact the Registrant Subsidiaries' net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. State Tax Legislation House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrant Subsidiaries' net income, cash flows or financial condition. |
Public Service Co Of Oklahoma [Member] | |
Income Taxes | INCOME TAXES AEP System Tax Allocation Agreement The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Federal and State Income Tax Audit Status The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact the Registrant Subsidiaries' net income. The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact the Registrant Subsidiaries' net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. State Tax Legislation House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrant Subsidiaries' net income, cash flows or financial condition. |
Southwestern Electric Power Co [Member] | |
Income Taxes | INCOME TAXES AEP System Tax Allocation Agreement The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Federal and State Income Tax Audit Status The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact the Registrant Subsidiaries' net income. The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact the Registrant Subsidiaries' net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. State Tax Legislation House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrant Subsidiaries' net income, cash flows or financial condition. |
Financing Activities
Financing Activities | 9 Months Ended |
Sep. 30, 2015 | |
Financing Activities | FINANCING ACTIVITIES Long-term Debt The following table details long-term debt outstanding as of September 30, 2015 and December 31, 2014 : Type of Debt September 30, 2015 December 31, 2014 (in millions) Senior Unsecured Notes $ 13,801 $ 12,647 Pollution Control Bonds 1,874 1,963 Notes Payable (a) 374 357 Securitization Bonds 2,072 2,380 Spent Nuclear Fuel Obligation (b) 266 266 Other Long-term Debt 1,151 1,101 Fair Value of Interest Rate Hedges — (6 ) Unamortized Discount, Net (31 ) (24 ) Total Long-term Debt Outstanding (a) 19,507 18,684 Long-term Debt Due Within One Year (a) 1,907 2,503 Long-term Debt (a) $ 17,600 $ 16,181 (a) Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. (b) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2015 and December 31, 2014 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the condensed balance sheets. Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2015 are shown in the tables below: Company Type of Debt Principal Amount Interest Rate Due Date Issuances: (in millions) (%) APCo Pollution Control Bonds $ 86 1.90 2019 APCo Senior Unsecured Notes 350 4.45 2045 APCo Senior Unsecured Notes 300 3.40 2025 I&M Notes Payable 111 Variable 2019 I&M Other Long-term Debt 100 Variable 2018 PSO Senior Unsecured Notes 125 3.17 2025 PSO Senior Unsecured Notes 125 4.09 2045 SWEPCo Pollution Control Bonds 54 1.60 2019 SWEPCo Senior Unsecured Notes 400 3.90 2045 Non-Registrant: AEPTCo Senior Unsecured Notes 60 4.01 2030 AEPTCo Senior Unsecured Notes 50 3.66 2025 AEPTCo Senior Unsecured Notes 40 3.76 2025 AGR Other Long-term Debt 500 Variable 2017 KPCo Other Long-term Debt 25 Variable 2018 TCC Senior Unsecured Notes 250 3.85 2025 TNC Senior Unsecured Notes 50 3.75 2025 TNC Senior Unsecured Notes 25 3.27 2022 Transource Missouri Other Long-term Debt 20 Variable 2018 WPCo Senior Unsecured Notes 113 3.36 2022 WPCo Senior Unsecured Notes 122 3.70 2025 WPCo Senior Unsecured Notes 50 4.20 2035 Total Issuances $ 2,956 (a) (a) Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the issuance amount. Company Type of Debt Principal Amount Paid Interest Due Date Total Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 23 2.008 2024 APCo Senior Unsecured Notes 350 7.95 2020 APCo Senior Unsecured Notes 300 3.40 2015 I&M Other Long-term Debt 94 Variable 2015 I&M Other Long-term Debt 1 6.00 2025 I&M Notes Payable 18 Variable 2016 I&M Notes Payable 21 Variable 2017 I&M Notes Payable 26 Variable 2019 I&M Notes Payable 16 Variable 2019 I&M Notes Payable 1 Variable 2016 I&M Notes Payable 1 2.12 2016 OPCo Pollution Control Bonds 86 3.125 2015 OPCo Securitization Bonds 45 0.958 2018 SWEPCo Notes Payable 3 4.58 2032 SWEPCo Pollution Control Bonds 54 3.25 2015 SWEPCo Senior Unsecured Notes 100 5.375 2015 SWEPCo Senior Unsecured Notes 150 4.90 2015 Non-Registrant: AEGCo Senior Unsecured Notes 7 6.33 2037 AEP Subsidiaries Notes Payable 5 Variable 2017 AEP Subsidiaries Notes Payable 1 (a) 7.59 2026 AEP Subsidiaries Notes Payable 1 (a) 8.03 2026 AGR Other Long-term Debt 500 Variable 2015 AGR Pollution Control Bonds 50 Variable 2015 AGR Pollution Control Bonds 39 Variable 2015 TCC Securitization Bonds 81 5.09 2015 TCC Securitization Bonds 76 6.25 2016 TCC Securitization Bonds 27 0.88 2017 TCC Securitization Bonds 57 5.17 2018 Total Retirements and Principal Payments $ 2,133 (a) (a) Amount includes principal payments of debt related to AEPRO that has been classified as Discontinued Operations on the condensed statement of cash flows. In October 2015, KPCo drew the remaining $25 million on an existing $75 million variable rate credit facility due in 2018 . In October 2015, Transource Missouri drew $6 million on an existing $300 million variable rate credit facility due in 2018 . As of September 30, 2015 , trustees held on our behalf, $475 million of our reacquired Pollution Control Bonds. Dividend Restrictions Parent Restrictions The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends. Our income primarily derives from our common stock equity in the earnings of our utility subsidiaries. Pursuant to the leverage restrictions in our credit agreements, we must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. None of AEP’s retained earnings were restricted for the purpose of the payment of dividends. Utility Subsidiaries’ Restrictions Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends. Specifically, several of our public utility subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings. Short-term Debt Our outstanding short-term debt was as follows: September 30, 2015 December 31, 2014 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 750 0.28 % $ 744 0.22 % Commercial Paper 32 0.44 % 602 0.59 % Total Short-term Debt $ 782 $ 1,346 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance. Credit Facilities For an additional discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivable – AEP Credit AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. AEP Credit continues to service the receivables. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables and accelerate AEP Credit’s cash collections. Our receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017. Accounts receivable information for AEP Credit is as follows: Three Months Ended Nine Months Ended 2015 2014 2015 2014 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.30 % 0.21 % 0.28 % 0.22 % Net Uncollectible Accounts Receivable Written Off $ 13 $ 16 $ 27 $ 32 September 30, 2015 December 31, 2014 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 970 $ 975 Total Principal Outstanding 750 744 Delinquent Securitized Accounts Receivable 50 44 Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable 16 13 Unbilled Receivables Related to Securitization/Sale of Accounts Receivable 277 335 Customer accounts receivable retained and securitized for our operating companies are managed by AEP Credit. AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due. |
Appalachian Power Co [Member] | |
Financing Activities | FINANCING ACTIVITIES Long-term Debt Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2015 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 28 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 22,524 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 20,601 Variable 2017 I&M Notes Payable 26,512 Variable 2019 I&M Notes Payable 16,265 Variable 2019 I&M Notes Payable 1,273 Variable 2016 I&M Notes Payable 882 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 838 6.00 2025 OPCo Other Long-term Debt 58 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 45,426 0.958 2018 PSO Other Long-term Debt 319 3.00 2027 SWEPCo Notes Payable 3,250 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 SWEPCo Senior Unsecured Notes 150,000 4.90 2015 As of September 30, 2015 , trustees held on behalf of I&M and OPCo, $40 million and $345 million , respectively, of their reacquired Pollution Control Bonds. Dividend Restrictions The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends. Federal Power Act The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. This restriction does not limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. Leverage Restrictions Pursuant to the credit agreement leverage restrictions, APCo, I&M, PSO and SWEPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5% . Utility Money Pool – AEP System The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds a majority of AEP's nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2015 and December 31, 2014 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ condensed balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2015 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 46,664 $ 97,657 $ (11,689 ) $ 600,000 I&M 200,032 13,515 136,890 13,503 (137,496 ) 500,000 OPCo — 367,472 — 256,020 279,129 400,000 PSO 165,947 152,498 113,117 74,225 116,345 300,000 SWEPCo 112,481 299,932 52,596 121,845 43,073 350,000 The activity in the above table does not include short-term lending activity of SWEPCo's wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2015 and December 31, 2014 are included in Advances to Affiliates on SWEPCo's condensed balance sheets. For the nine months ended September 30, 2015 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Maximum Average Average Loans Borrowings Loans Borrowings Loans to the Nonutility from the Nonutility to the Nonutility from the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool Money Pool Money Pool September 30, 2015 (in thousands) $ — $ 1,948 $ — $ 1,945 $ 1,946 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Nine Months Ended September 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2015 and 2014 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 APCo 0.46 % 0.26 % 0.46 % 0.28 % I&M 0.47 % 0.27 % 0.46 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.27 % 0.46 % — % SWEPCo 0.46 % 0.28 % 0.48 % 0.27 % Maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool for the nine months ended September 30, 2015 and 2014 are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Nine Months Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to Ended the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility September 30, Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool 2015 — % — % 0.59 % 0.39 % — % 0.47 % 2014 — % — % 0.33 % — % — % 0.28 % Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Sale of Receivables – AEP Credit Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold. AEP Credit's receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2015 and December 31, 2014 was as follows: September 30, December 31, Company 2015 2014 (in thousands) APCo $ 125,153 $ 159,823 I&M 139,481 137,459 OPCo 354,276 365,834 PSO 146,039 112,905 SWEPCo 176,113 148,668 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,952 $ 2,166 $ 5,979 $ 6,626 I&M 2,191 2,011 6,611 5,836 OPCo 8,545 7,213 23,228 21,358 PSO 1,709 1,745 4,455 4,417 SWEPCo 1,997 1,890 5,344 5,035 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 355,275 $ 354,406 $ 1,115,492 $ 1,137,564 I&M 401,518 372,422 1,192,137 1,132,603 OPCo 670,677 668,112 1,949,042 1,980,764 PSO 411,523 398,567 1,025,909 1,014,320 SWEPCo 468,027 466,828 1,222,294 1,278,325 |
Indiana Michigan Power Co [Member] | |
Financing Activities | FINANCING ACTIVITIES Long-term Debt Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2015 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 28 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 22,524 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 20,601 Variable 2017 I&M Notes Payable 26,512 Variable 2019 I&M Notes Payable 16,265 Variable 2019 I&M Notes Payable 1,273 Variable 2016 I&M Notes Payable 882 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 838 6.00 2025 OPCo Other Long-term Debt 58 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 45,426 0.958 2018 PSO Other Long-term Debt 319 3.00 2027 SWEPCo Notes Payable 3,250 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 SWEPCo Senior Unsecured Notes 150,000 4.90 2015 As of September 30, 2015 , trustees held on behalf of I&M and OPCo, $40 million and $345 million , respectively, of their reacquired Pollution Control Bonds. Dividend Restrictions The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends. Federal Power Act The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. This restriction does not limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. Leverage Restrictions Pursuant to the credit agreement leverage restrictions, APCo, I&M, PSO and SWEPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5% . Utility Money Pool – AEP System The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds a majority of AEP's nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2015 and December 31, 2014 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ condensed balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2015 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 46,664 $ 97,657 $ (11,689 ) $ 600,000 I&M 200,032 13,515 136,890 13,503 (137,496 ) 500,000 OPCo — 367,472 — 256,020 279,129 400,000 PSO 165,947 152,498 113,117 74,225 116,345 300,000 SWEPCo 112,481 299,932 52,596 121,845 43,073 350,000 The activity in the above table does not include short-term lending activity of SWEPCo's wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2015 and December 31, 2014 are included in Advances to Affiliates on SWEPCo's condensed balance sheets. For the nine months ended September 30, 2015 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Maximum Average Average Loans Borrowings Loans Borrowings Loans to the Nonutility from the Nonutility to the Nonutility from the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool Money Pool Money Pool September 30, 2015 (in thousands) $ — $ 1,948 $ — $ 1,945 $ 1,946 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Nine Months Ended September 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2015 and 2014 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 APCo 0.46 % 0.26 % 0.46 % 0.28 % I&M 0.47 % 0.27 % 0.46 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.27 % 0.46 % — % SWEPCo 0.46 % 0.28 % 0.48 % 0.27 % Maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool for the nine months ended September 30, 2015 and 2014 are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Nine Months Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to Ended the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility September 30, Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool 2015 — % — % 0.59 % 0.39 % — % 0.47 % 2014 — % — % 0.33 % — % — % 0.28 % Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Sale of Receivables – AEP Credit Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold. AEP Credit's receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2015 and December 31, 2014 was as follows: September 30, December 31, Company 2015 2014 (in thousands) APCo $ 125,153 $ 159,823 I&M 139,481 137,459 OPCo 354,276 365,834 PSO 146,039 112,905 SWEPCo 176,113 148,668 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,952 $ 2,166 $ 5,979 $ 6,626 I&M 2,191 2,011 6,611 5,836 OPCo 8,545 7,213 23,228 21,358 PSO 1,709 1,745 4,455 4,417 SWEPCo 1,997 1,890 5,344 5,035 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 355,275 $ 354,406 $ 1,115,492 $ 1,137,564 I&M 401,518 372,422 1,192,137 1,132,603 OPCo 670,677 668,112 1,949,042 1,980,764 PSO 411,523 398,567 1,025,909 1,014,320 SWEPCo 468,027 466,828 1,222,294 1,278,325 |
Ohio Power Co [Member] | |
Financing Activities | FINANCING ACTIVITIES Long-term Debt Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2015 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 28 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 22,524 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 20,601 Variable 2017 I&M Notes Payable 26,512 Variable 2019 I&M Notes Payable 16,265 Variable 2019 I&M Notes Payable 1,273 Variable 2016 I&M Notes Payable 882 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 838 6.00 2025 OPCo Other Long-term Debt 58 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 45,426 0.958 2018 PSO Other Long-term Debt 319 3.00 2027 SWEPCo Notes Payable 3,250 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 SWEPCo Senior Unsecured Notes 150,000 4.90 2015 As of September 30, 2015 , trustees held on behalf of I&M and OPCo, $40 million and $345 million , respectively, of their reacquired Pollution Control Bonds. Dividend Restrictions The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends. Federal Power Act The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. This restriction does not limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. Leverage Restrictions Pursuant to the credit agreement leverage restrictions, APCo, I&M, PSO and SWEPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5% . Utility Money Pool – AEP System The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds a majority of AEP's nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2015 and December 31, 2014 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ condensed balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2015 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 46,664 $ 97,657 $ (11,689 ) $ 600,000 I&M 200,032 13,515 136,890 13,503 (137,496 ) 500,000 OPCo — 367,472 — 256,020 279,129 400,000 PSO 165,947 152,498 113,117 74,225 116,345 300,000 SWEPCo 112,481 299,932 52,596 121,845 43,073 350,000 The activity in the above table does not include short-term lending activity of SWEPCo's wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2015 and December 31, 2014 are included in Advances to Affiliates on SWEPCo's condensed balance sheets. For the nine months ended September 30, 2015 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Maximum Average Average Loans Borrowings Loans Borrowings Loans to the Nonutility from the Nonutility to the Nonutility from the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool Money Pool Money Pool September 30, 2015 (in thousands) $ — $ 1,948 $ — $ 1,945 $ 1,946 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Nine Months Ended September 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2015 and 2014 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 APCo 0.46 % 0.26 % 0.46 % 0.28 % I&M 0.47 % 0.27 % 0.46 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.27 % 0.46 % — % SWEPCo 0.46 % 0.28 % 0.48 % 0.27 % Maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool for the nine months ended September 30, 2015 and 2014 are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Nine Months Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to Ended the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility September 30, Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool 2015 — % — % 0.59 % 0.39 % — % 0.47 % 2014 — % — % 0.33 % — % — % 0.28 % Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Sale of Receivables – AEP Credit Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold. AEP Credit's receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2015 and December 31, 2014 was as follows: September 30, December 31, Company 2015 2014 (in thousands) APCo $ 125,153 $ 159,823 I&M 139,481 137,459 OPCo 354,276 365,834 PSO 146,039 112,905 SWEPCo 176,113 148,668 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,952 $ 2,166 $ 5,979 $ 6,626 I&M 2,191 2,011 6,611 5,836 OPCo 8,545 7,213 23,228 21,358 PSO 1,709 1,745 4,455 4,417 SWEPCo 1,997 1,890 5,344 5,035 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 355,275 $ 354,406 $ 1,115,492 $ 1,137,564 I&M 401,518 372,422 1,192,137 1,132,603 OPCo 670,677 668,112 1,949,042 1,980,764 PSO 411,523 398,567 1,025,909 1,014,320 SWEPCo 468,027 466,828 1,222,294 1,278,325 |
Public Service Co Of Oklahoma [Member] | |
Financing Activities | FINANCING ACTIVITIES Long-term Debt Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2015 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 28 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 22,524 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 20,601 Variable 2017 I&M Notes Payable 26,512 Variable 2019 I&M Notes Payable 16,265 Variable 2019 I&M Notes Payable 1,273 Variable 2016 I&M Notes Payable 882 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 838 6.00 2025 OPCo Other Long-term Debt 58 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 45,426 0.958 2018 PSO Other Long-term Debt 319 3.00 2027 SWEPCo Notes Payable 3,250 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 SWEPCo Senior Unsecured Notes 150,000 4.90 2015 As of September 30, 2015 , trustees held on behalf of I&M and OPCo, $40 million and $345 million , respectively, of their reacquired Pollution Control Bonds. Dividend Restrictions The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends. Federal Power Act The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. This restriction does not limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. Leverage Restrictions Pursuant to the credit agreement leverage restrictions, APCo, I&M, PSO and SWEPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5% . Utility Money Pool – AEP System The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds a majority of AEP's nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2015 and December 31, 2014 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ condensed balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2015 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 46,664 $ 97,657 $ (11,689 ) $ 600,000 I&M 200,032 13,515 136,890 13,503 (137,496 ) 500,000 OPCo — 367,472 — 256,020 279,129 400,000 PSO 165,947 152,498 113,117 74,225 116,345 300,000 SWEPCo 112,481 299,932 52,596 121,845 43,073 350,000 The activity in the above table does not include short-term lending activity of SWEPCo's wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2015 and December 31, 2014 are included in Advances to Affiliates on SWEPCo's condensed balance sheets. For the nine months ended September 30, 2015 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Maximum Average Average Loans Borrowings Loans Borrowings Loans to the Nonutility from the Nonutility to the Nonutility from the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool Money Pool Money Pool September 30, 2015 (in thousands) $ — $ 1,948 $ — $ 1,945 $ 1,946 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Nine Months Ended September 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2015 and 2014 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 APCo 0.46 % 0.26 % 0.46 % 0.28 % I&M 0.47 % 0.27 % 0.46 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.27 % 0.46 % — % SWEPCo 0.46 % 0.28 % 0.48 % 0.27 % Maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool for the nine months ended September 30, 2015 and 2014 are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Nine Months Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to Ended the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility September 30, Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool 2015 — % — % 0.59 % 0.39 % — % 0.47 % 2014 — % — % 0.33 % — % — % 0.28 % Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Sale of Receivables – AEP Credit Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold. AEP Credit's receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2015 and December 31, 2014 was as follows: September 30, December 31, Company 2015 2014 (in thousands) APCo $ 125,153 $ 159,823 I&M 139,481 137,459 OPCo 354,276 365,834 PSO 146,039 112,905 SWEPCo 176,113 148,668 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,952 $ 2,166 $ 5,979 $ 6,626 I&M 2,191 2,011 6,611 5,836 OPCo 8,545 7,213 23,228 21,358 PSO 1,709 1,745 4,455 4,417 SWEPCo 1,997 1,890 5,344 5,035 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 355,275 $ 354,406 $ 1,115,492 $ 1,137,564 I&M 401,518 372,422 1,192,137 1,132,603 OPCo 670,677 668,112 1,949,042 1,980,764 PSO 411,523 398,567 1,025,909 1,014,320 SWEPCo 468,027 466,828 1,222,294 1,278,325 |
Southwestern Electric Power Co [Member] | |
Financing Activities | FINANCING ACTIVITIES Long-term Debt Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2015 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 28 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 22,524 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 20,601 Variable 2017 I&M Notes Payable 26,512 Variable 2019 I&M Notes Payable 16,265 Variable 2019 I&M Notes Payable 1,273 Variable 2016 I&M Notes Payable 882 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 838 6.00 2025 OPCo Other Long-term Debt 58 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 45,426 0.958 2018 PSO Other Long-term Debt 319 3.00 2027 SWEPCo Notes Payable 3,250 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 SWEPCo Senior Unsecured Notes 150,000 4.90 2015 As of September 30, 2015 , trustees held on behalf of I&M and OPCo, $40 million and $345 million , respectively, of their reacquired Pollution Control Bonds. Dividend Restrictions The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends. Federal Power Act The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. This restriction does not limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. Leverage Restrictions Pursuant to the credit agreement leverage restrictions, APCo, I&M, PSO and SWEPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5% . Utility Money Pool – AEP System The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds a majority of AEP's nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of September 30, 2015 and December 31, 2014 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ condensed balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2015 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 46,664 $ 97,657 $ (11,689 ) $ 600,000 I&M 200,032 13,515 136,890 13,503 (137,496 ) 500,000 OPCo — 367,472 — 256,020 279,129 400,000 PSO 165,947 152,498 113,117 74,225 116,345 300,000 SWEPCo 112,481 299,932 52,596 121,845 43,073 350,000 The activity in the above table does not include short-term lending activity of SWEPCo's wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of September 30, 2015 and December 31, 2014 are included in Advances to Affiliates on SWEPCo's condensed balance sheets. For the nine months ended September 30, 2015 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Maximum Average Average Loans Borrowings Loans Borrowings Loans to the Nonutility from the Nonutility to the Nonutility from the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool Money Pool Money Pool September 30, 2015 (in thousands) $ — $ 1,948 $ — $ 1,945 $ 1,946 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Nine Months Ended September 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2015 and 2014 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 APCo 0.46 % 0.26 % 0.46 % 0.28 % I&M 0.47 % 0.27 % 0.46 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.27 % 0.46 % — % SWEPCo 0.46 % 0.28 % 0.48 % 0.27 % Maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool for the nine months ended September 30, 2015 and 2014 are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Nine Months Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to Ended the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility September 30, Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool 2015 — % — % 0.59 % 0.39 % — % 0.47 % 2014 — % — % 0.33 % — % — % 0.28 % Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Sale of Receivables – AEP Credit Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold. AEP Credit's receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2015 and December 31, 2014 was as follows: September 30, December 31, Company 2015 2014 (in thousands) APCo $ 125,153 $ 159,823 I&M 139,481 137,459 OPCo 354,276 365,834 PSO 146,039 112,905 SWEPCo 176,113 148,668 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,952 $ 2,166 $ 5,979 $ 6,626 I&M 2,191 2,011 6,611 5,836 OPCo 8,545 7,213 23,228 21,358 PSO 1,709 1,745 4,455 4,417 SWEPCo 1,997 1,890 5,344 5,035 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 355,275 $ 354,406 $ 1,115,492 $ 1,137,564 I&M 401,518 372,422 1,192,137 1,132,603 OPCo 670,677 668,112 1,949,042 1,980,764 PSO 411,523 398,567 1,025,909 1,014,320 SWEPCo 468,027 466,828 1,222,294 1,278,325 |
Variable Interest Entities
Variable Interest Entities | 9 Months Ended |
Sep. 30, 2015 | |
Variable Interest Entities | VARIABLE INTEREST ENTITIES The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE’s variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. We believe that significant assumptions and judgments were applied consistently. We are the primary beneficiary of Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, a protected cell of EIS and Transource Energy. In addition, we have not provided material financial or other support to any of these entities that was not previously contractually required. We hold a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended September 30, 2015 and 2014 were $41 million and $41 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $124 million and $121 million , respectively. See the tables below for the classification of Sabine’s assets and liabilities on the condensed balance sheets. I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended September 30, 2015 and 2014 were $29 million and $28 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $86 million and $84 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on the condensed balance sheets. AEP Credit is a wholly-owned subsidiary of AEP. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on our control of AEP Credit, management concluded that we are the primary beneficiary and are required to consolidate AEP Credit. See the tables below for the classification of AEP Credit’s assets and liabilities on the condensed balance sheets. See “Securitized Accounts Receivable – AEP Credit” section of Note 12 . Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $1.5 billion and $1.8 billion as of September 30, 2015 and December 31, 2014 , respectively. Transition Funding has securitized transition assets of $1.4 billion and $1.6 billion as of September 30, 2015 and December 31, 2014 , respectively. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the condensed balance sheets. Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $187 million and $232 million as of September 30, 2015 and December 31, 2014 , respectively. Ohio Phase-in-Recovery Funding has securitized assets of $92 million and $110 million as of September 30, 2015 and December 31, 2014 , respectively. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding's assets and liabilities on the condensed balance sheets. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $345 million and $368 million as of September 30, 2015 and December 31, 2014 , respectively. Appalachian Consumer Rate Relief Funding has securitized assets of $333 million and $350 million as of September 30, 2015 and December 31, 2014 , respectively. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Appalachian Consumer Rate Relief Funding's assets and liabilities on the condensed balance sheets. The securitized bonds of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. The securitized assets of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in Securitized Assets on the condensed balance sheets. Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on our control and the structure of the protected cell of EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate the protected cell of EIS. Our insurance premium expense to the protected cell for the three months ended September 30, 2015 and 2014 was $13 million and $16 million , respectively, and for the nine months ended September 30, 2015 and 2014 was $27 million and $33 million , respectively. See the tables below for the classification of the protected cell’s assets and liabilities on the condensed balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus. Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity. Therefore, AEP is required to consolidate Transource Energy. AEP’s equity interest could potentially be significant. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP provided capital contributions to Transource Energy of $32 million and $23 million during the nine months ended September 30, 2015 and the year ended December 31, 2014 , respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. See the tables below for the classification of Transource Energy’s assets and liabilities on the condensed balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES September 30, 2015 (in millions) SWEPCo Sabine I&M DCC Fuel AEP Credit TCC Transition Funding OPCo Ohio Phase-in- Recovery Funding APCo Appalachian Consumer Rate Relief Funding Protected Cell of EIS Transource Energy ASSETS Current Assets $ 61 $ 104 $ 977 $ 197 $ 20 $ 11 $ 163 $ 12 Net Property, Plant and Equipment 144 193 — — — — — 184 Other Noncurrent Assets 60 101 1 1,454 (a) 175 (b) 341 (c) 3 5 Total Assets $ 265 $ 398 $ 978 $ 1,651 $ 195 $ 352 $ 166 $ 201 LIABILITIES AND EQUITY Current Liabilities $ 40 $ 98 $ 875 $ 283 $ 47 $ 25 $ 49 $ 47 Noncurrent Liabilities 225 300 1 1,350 147 325 76 80 Equity — — 102 18 1 2 41 74 Total Liabilities and Equity $ 265 $ 398 $ 978 $ 1,651 $ 195 $ 352 $ 166 $ 201 (a) Includes an intercompany item eliminated in consolidation of $70 million . (b) Includes an intercompany item eliminated in consolidation of $81 million . (c) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 (in millions) SWEPCo Sabine I&M DCC Fuel AEP Credit TCC Transition Funding OPCo Ohio Phase-in- Recovery Funding APCo Appalachian Consumer Rate Relief Funding Protected Cell of EIS Transource Energy ASSETS Current Assets $ 68 $ 97 $ 980 $ 239 $ 33 $ 18 $ 149 $ 2 Net Property, Plant and Equipment 145 158 — — — — — 98 Other Noncurrent Assets 52 80 — 1,654 (a) 210 (b) 358 (c) 2 4 Total Assets $ 265 $ 335 $ 980 $ 1,893 $ 243 $ 376 $ 151 $ 104 LIABILITIES AND EQUITY Current Liabilities $ 36 $ 86 $ 894 $ 322 $ 47 $ 27 $ 44 $ 21 Noncurrent Liabilities 228 249 — 1,553 195 347 62 55 Equity 1 — 86 18 1 2 45 28 Total Liabilities and Equity $ 265 $ 335 $ 980 $ 1,893 $ 243 $ 376 $ 151 $ 104 (a) Includes an intercompany item eliminated in consolidation of $75 million . (b) Includes an intercompany item eliminated in consolidation of $97 million . (c) Includes an intercompany item eliminated in consolidation of $4 million . DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended September 30, 2015 and 2014 were $30 million and $24 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $59 million and $31 million , respectively. We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC. Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Our investment in DHLC was: September 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from SWEPCo $ 8 $ 8 $ 8 $ 8 Retained Earnings 6 6 4 4 Advance Due to Parent 40 40 56 56 Guarantee of Debt — 55 — 48 Total Investment in DHLC $ 54 $ 109 $ 68 $ 116 We and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned and controlled by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV. Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on our condensed balance sheets. We and FirstEnergy share the returns and losses equally in PATH-WV. Our subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements. The entities recover costs through regulated rates. In August 2012, the PJM board cancelled the PATH Project, the transmission project that PATH was intended to develop, and removed it from the 2012 Regional Transmission Expansion Plan. In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project's abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at FERC were held in March and April 2015. In September 2015, the Administrative Law Judge who conducted the hearings issued an Initial Decision, with recommendations on various issues in the case. The Initial Decision has no binding effect. Additional briefing is scheduled during the fourth quarter of 2015, after which the case will be pending before FERC. Our investment in PATH-WV was: September 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from AEP $ 19 $ 19 $ 19 $ 19 Retained Earnings 2 2 2 2 Total Investment in PATH-WV $ 21 $ 21 $ 21 $ 21 As of September 30, 2015 , our $21 million investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheet. We believe the financial statements adequately address the impact of the Initial Decision. If we cannot ultimately recover our investment related to PATH-WV, it could reduce future net income and cash flows. |
Appalachian Power Co [Member] | |
Variable Interest Entities | VARIABLE INTEREST ENTITIES The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding. In addition, the Registrant Subsidiaries have not provided material financial or other support to any of these entities that was not previously contractually required. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M holds a significant variable interest in AEGCo. Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended September 30, 2015 and 2014 were $41 million and $41 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $124 million and $121 million , respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets. The balances below represent the assets and liabilities of Sabine that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Sabine ASSETS 2015 2014 Current Assets $ 61,025 $ 67,981 Net Property, Plant and Equipment 143,815 145,491 Other Noncurrent Assets 60,160 51,578 Total Assets $ 265,000 $ 265,050 LIABILITIES AND EQUITY Current Liabilities $ 40,311 $ 36,286 Noncurrent Liabilities 224,371 228,349 Equity 318 415 Total Liabilities and Equity $ 265,000 $ 265,050 I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended September 30, 2015 and 2014 were $29 million and $28 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $86 million and $84 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months . Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets. The balances below represent the assets and liabilities of DCC Fuel that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) DCC Fuel ASSETS 2015 2014 Current Assets $ 104,273 $ 97,361 Net Property, Plant and Equipment 193,447 158,121 Other Noncurrent Assets 99,811 79,705 Total Assets $ 397,531 $ 335,187 LIABILITIES AND EQUITY Current Liabilities $ 98,173 $ 86,026 Noncurrent Liabilities 299,358 249,161 Total Liabilities and Equity $ 397,531 $ 335,187 Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $187 million and $232 million as of September 30, 2015 and December 31, 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $92 million and $110 million as of September 30, 2015 and December 31, 2014 , respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s condensed balance sheets. The balances below represent the assets and liabilities of Ohio Phase-in-Recovery Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. OHIO POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Ohio Phase-In Recovery Funding ASSETS 2015 2014 Current Assets $ 20,236 $ 32,676 Other Noncurrent Assets (a) 175,189 209,922 Total Assets $ 195,425 $ 242,598 LIABILITIES AND EQUITY Current Liabilities $ 46,592 $ 47,099 Noncurrent Liabilities 147,496 194,162 Equity 1,337 1,337 Total Liabilities and Equity $ 195,425 $ 242,598 (a) Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $81 million and $97 million , respectively. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $345 million and $368 million as of September 30, 2015 and December 31, 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $333 million and $350 million as of September 30, 2015 and December 31, 2014 , respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s condensed balance sheets. The balances below represent the assets and liabilities of Appalachian Consumer Rate Relief Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. APPALACHIAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Appalachian Consumer Rate Relief Funding ASSETS 2015 2014 Current Assets $ 10,914 $ 18,099 Other Noncurrent Assets (a) 341,127 358,264 Total Assets $ 352,041 $ 376,363 LIABILITIES AND EQUITY Current Liabilities $ 24,617 $ 26,809 Noncurrent Liabilities 325,534 347,652 Equity 1,890 1,902 Total Liabilities and Equity $ 352,041 $ 376,363 (a) Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $4 million and $4 million , respectively. DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended September 30, 2015 and 2014 were $30 million and $24 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $59 million and $31 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets. SWEPCo’s investment in DHLC was: September 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) Capital Contribution from SWEPCo $ 7,643 $ 7,643 $ 7,643 $ 7,643 Retained Earnings 5,950 5,950 3,819 3,819 SWEPCo's Guarantee of Debt — 95,180 (a) — 104,334 (a) Total Investment in DHLC $ 13,593 $ 108,773 $ 11,462 $ 115,796 (a) Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $40 million and $56 million in 2015 and 2014 , respectively. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 63,687 $ 50,143 $ 164,657 $ 154,239 I&M 37,506 30,613 102,141 92,686 OPCo 48,471 41,212 128,608 120,696 PSO 29,851 24,317 77,817 71,646 SWEPCo 39,150 32,787 102,564 98,528 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: September 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 23,783 $ 23,783 $ 30,692 $ 30,692 I&M 13,676 13,676 22,480 22,480 OPCo 18,770 18,770 24,695 24,695 PSO 10,713 10,713 15,338 15,338 SWEPCo 14,295 14,295 20,772 20,772 AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo and AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligation of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the three months ended September 30, 2015 and 2014 were $67 million and $67 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $182 million and $202 million , respectively. The carrying amount of I&M's liabilities associated with AEGCo as of September 30, 2015 and December 31, 2014 was $17 million and $20 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo's lease, see "Rockport Lease" section of Note 13 in the 2014 Annual Report. |
Indiana Michigan Power Co [Member] | |
Variable Interest Entities | VARIABLE INTEREST ENTITIES The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding. In addition, the Registrant Subsidiaries have not provided material financial or other support to any of these entities that was not previously contractually required. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M holds a significant variable interest in AEGCo. Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended September 30, 2015 and 2014 were $41 million and $41 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $124 million and $121 million , respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets. The balances below represent the assets and liabilities of Sabine that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Sabine ASSETS 2015 2014 Current Assets $ 61,025 $ 67,981 Net Property, Plant and Equipment 143,815 145,491 Other Noncurrent Assets 60,160 51,578 Total Assets $ 265,000 $ 265,050 LIABILITIES AND EQUITY Current Liabilities $ 40,311 $ 36,286 Noncurrent Liabilities 224,371 228,349 Equity 318 415 Total Liabilities and Equity $ 265,000 $ 265,050 I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended September 30, 2015 and 2014 were $29 million and $28 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $86 million and $84 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months . Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets. The balances below represent the assets and liabilities of DCC Fuel that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) DCC Fuel ASSETS 2015 2014 Current Assets $ 104,273 $ 97,361 Net Property, Plant and Equipment 193,447 158,121 Other Noncurrent Assets 99,811 79,705 Total Assets $ 397,531 $ 335,187 LIABILITIES AND EQUITY Current Liabilities $ 98,173 $ 86,026 Noncurrent Liabilities 299,358 249,161 Total Liabilities and Equity $ 397,531 $ 335,187 Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $187 million and $232 million as of September 30, 2015 and December 31, 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $92 million and $110 million as of September 30, 2015 and December 31, 2014 , respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s condensed balance sheets. The balances below represent the assets and liabilities of Ohio Phase-in-Recovery Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. OHIO POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Ohio Phase-In Recovery Funding ASSETS 2015 2014 Current Assets $ 20,236 $ 32,676 Other Noncurrent Assets (a) 175,189 209,922 Total Assets $ 195,425 $ 242,598 LIABILITIES AND EQUITY Current Liabilities $ 46,592 $ 47,099 Noncurrent Liabilities 147,496 194,162 Equity 1,337 1,337 Total Liabilities and Equity $ 195,425 $ 242,598 (a) Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $81 million and $97 million , respectively. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $345 million and $368 million as of September 30, 2015 and December 31, 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $333 million and $350 million as of September 30, 2015 and December 31, 2014 , respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s condensed balance sheets. The balances below represent the assets and liabilities of Appalachian Consumer Rate Relief Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. APPALACHIAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Appalachian Consumer Rate Relief Funding ASSETS 2015 2014 Current Assets $ 10,914 $ 18,099 Other Noncurrent Assets (a) 341,127 358,264 Total Assets $ 352,041 $ 376,363 LIABILITIES AND EQUITY Current Liabilities $ 24,617 $ 26,809 Noncurrent Liabilities 325,534 347,652 Equity 1,890 1,902 Total Liabilities and Equity $ 352,041 $ 376,363 (a) Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $4 million and $4 million , respectively. DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended September 30, 2015 and 2014 were $30 million and $24 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $59 million and $31 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets. SWEPCo’s investment in DHLC was: September 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) Capital Contribution from SWEPCo $ 7,643 $ 7,643 $ 7,643 $ 7,643 Retained Earnings 5,950 5,950 3,819 3,819 SWEPCo's Guarantee of Debt — 95,180 (a) — 104,334 (a) Total Investment in DHLC $ 13,593 $ 108,773 $ 11,462 $ 115,796 (a) Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $40 million and $56 million in 2015 and 2014 , respectively. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 63,687 $ 50,143 $ 164,657 $ 154,239 I&M 37,506 30,613 102,141 92,686 OPCo 48,471 41,212 128,608 120,696 PSO 29,851 24,317 77,817 71,646 SWEPCo 39,150 32,787 102,564 98,528 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: September 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 23,783 $ 23,783 $ 30,692 $ 30,692 I&M 13,676 13,676 22,480 22,480 OPCo 18,770 18,770 24,695 24,695 PSO 10,713 10,713 15,338 15,338 SWEPCo 14,295 14,295 20,772 20,772 AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo and AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligation of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the three months ended September 30, 2015 and 2014 were $67 million and $67 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $182 million and $202 million , respectively. The carrying amount of I&M's liabilities associated with AEGCo as of September 30, 2015 and December 31, 2014 was $17 million and $20 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo's lease, see "Rockport Lease" section of Note 13 in the 2014 Annual Report. |
Ohio Power Co [Member] | |
Variable Interest Entities | VARIABLE INTEREST ENTITIES The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding. In addition, the Registrant Subsidiaries have not provided material financial or other support to any of these entities that was not previously contractually required. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M holds a significant variable interest in AEGCo. Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended September 30, 2015 and 2014 were $41 million and $41 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $124 million and $121 million , respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets. The balances below represent the assets and liabilities of Sabine that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Sabine ASSETS 2015 2014 Current Assets $ 61,025 $ 67,981 Net Property, Plant and Equipment 143,815 145,491 Other Noncurrent Assets 60,160 51,578 Total Assets $ 265,000 $ 265,050 LIABILITIES AND EQUITY Current Liabilities $ 40,311 $ 36,286 Noncurrent Liabilities 224,371 228,349 Equity 318 415 Total Liabilities and Equity $ 265,000 $ 265,050 I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended September 30, 2015 and 2014 were $29 million and $28 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $86 million and $84 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months . Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets. The balances below represent the assets and liabilities of DCC Fuel that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) DCC Fuel ASSETS 2015 2014 Current Assets $ 104,273 $ 97,361 Net Property, Plant and Equipment 193,447 158,121 Other Noncurrent Assets 99,811 79,705 Total Assets $ 397,531 $ 335,187 LIABILITIES AND EQUITY Current Liabilities $ 98,173 $ 86,026 Noncurrent Liabilities 299,358 249,161 Total Liabilities and Equity $ 397,531 $ 335,187 Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $187 million and $232 million as of September 30, 2015 and December 31, 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $92 million and $110 million as of September 30, 2015 and December 31, 2014 , respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s condensed balance sheets. The balances below represent the assets and liabilities of Ohio Phase-in-Recovery Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. OHIO POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Ohio Phase-In Recovery Funding ASSETS 2015 2014 Current Assets $ 20,236 $ 32,676 Other Noncurrent Assets (a) 175,189 209,922 Total Assets $ 195,425 $ 242,598 LIABILITIES AND EQUITY Current Liabilities $ 46,592 $ 47,099 Noncurrent Liabilities 147,496 194,162 Equity 1,337 1,337 Total Liabilities and Equity $ 195,425 $ 242,598 (a) Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $81 million and $97 million , respectively. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $345 million and $368 million as of September 30, 2015 and December 31, 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $333 million and $350 million as of September 30, 2015 and December 31, 2014 , respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s condensed balance sheets. The balances below represent the assets and liabilities of Appalachian Consumer Rate Relief Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. APPALACHIAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Appalachian Consumer Rate Relief Funding ASSETS 2015 2014 Current Assets $ 10,914 $ 18,099 Other Noncurrent Assets (a) 341,127 358,264 Total Assets $ 352,041 $ 376,363 LIABILITIES AND EQUITY Current Liabilities $ 24,617 $ 26,809 Noncurrent Liabilities 325,534 347,652 Equity 1,890 1,902 Total Liabilities and Equity $ 352,041 $ 376,363 (a) Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $4 million and $4 million , respectively. DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended September 30, 2015 and 2014 were $30 million and $24 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $59 million and $31 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets. SWEPCo’s investment in DHLC was: September 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) Capital Contribution from SWEPCo $ 7,643 $ 7,643 $ 7,643 $ 7,643 Retained Earnings 5,950 5,950 3,819 3,819 SWEPCo's Guarantee of Debt — 95,180 (a) — 104,334 (a) Total Investment in DHLC $ 13,593 $ 108,773 $ 11,462 $ 115,796 (a) Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $40 million and $56 million in 2015 and 2014 , respectively. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 63,687 $ 50,143 $ 164,657 $ 154,239 I&M 37,506 30,613 102,141 92,686 OPCo 48,471 41,212 128,608 120,696 PSO 29,851 24,317 77,817 71,646 SWEPCo 39,150 32,787 102,564 98,528 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: September 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 23,783 $ 23,783 $ 30,692 $ 30,692 I&M 13,676 13,676 22,480 22,480 OPCo 18,770 18,770 24,695 24,695 PSO 10,713 10,713 15,338 15,338 SWEPCo 14,295 14,295 20,772 20,772 AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo and AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligation of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the three months ended September 30, 2015 and 2014 were $67 million and $67 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $182 million and $202 million , respectively. The carrying amount of I&M's liabilities associated with AEGCo as of September 30, 2015 and December 31, 2014 was $17 million and $20 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo's lease, see "Rockport Lease" section of Note 13 in the 2014 Annual Report. |
Public Service Co Of Oklahoma [Member] | |
Variable Interest Entities | VARIABLE INTEREST ENTITIES The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding. In addition, the Registrant Subsidiaries have not provided material financial or other support to any of these entities that was not previously contractually required. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M holds a significant variable interest in AEGCo. Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended September 30, 2015 and 2014 were $41 million and $41 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $124 million and $121 million , respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets. The balances below represent the assets and liabilities of Sabine that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Sabine ASSETS 2015 2014 Current Assets $ 61,025 $ 67,981 Net Property, Plant and Equipment 143,815 145,491 Other Noncurrent Assets 60,160 51,578 Total Assets $ 265,000 $ 265,050 LIABILITIES AND EQUITY Current Liabilities $ 40,311 $ 36,286 Noncurrent Liabilities 224,371 228,349 Equity 318 415 Total Liabilities and Equity $ 265,000 $ 265,050 I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended September 30, 2015 and 2014 were $29 million and $28 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $86 million and $84 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months . Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets. The balances below represent the assets and liabilities of DCC Fuel that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) DCC Fuel ASSETS 2015 2014 Current Assets $ 104,273 $ 97,361 Net Property, Plant and Equipment 193,447 158,121 Other Noncurrent Assets 99,811 79,705 Total Assets $ 397,531 $ 335,187 LIABILITIES AND EQUITY Current Liabilities $ 98,173 $ 86,026 Noncurrent Liabilities 299,358 249,161 Total Liabilities and Equity $ 397,531 $ 335,187 Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $187 million and $232 million as of September 30, 2015 and December 31, 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $92 million and $110 million as of September 30, 2015 and December 31, 2014 , respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s condensed balance sheets. The balances below represent the assets and liabilities of Ohio Phase-in-Recovery Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. OHIO POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Ohio Phase-In Recovery Funding ASSETS 2015 2014 Current Assets $ 20,236 $ 32,676 Other Noncurrent Assets (a) 175,189 209,922 Total Assets $ 195,425 $ 242,598 LIABILITIES AND EQUITY Current Liabilities $ 46,592 $ 47,099 Noncurrent Liabilities 147,496 194,162 Equity 1,337 1,337 Total Liabilities and Equity $ 195,425 $ 242,598 (a) Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $81 million and $97 million , respectively. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $345 million and $368 million as of September 30, 2015 and December 31, 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $333 million and $350 million as of September 30, 2015 and December 31, 2014 , respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s condensed balance sheets. The balances below represent the assets and liabilities of Appalachian Consumer Rate Relief Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. APPALACHIAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Appalachian Consumer Rate Relief Funding ASSETS 2015 2014 Current Assets $ 10,914 $ 18,099 Other Noncurrent Assets (a) 341,127 358,264 Total Assets $ 352,041 $ 376,363 LIABILITIES AND EQUITY Current Liabilities $ 24,617 $ 26,809 Noncurrent Liabilities 325,534 347,652 Equity 1,890 1,902 Total Liabilities and Equity $ 352,041 $ 376,363 (a) Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $4 million and $4 million , respectively. DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended September 30, 2015 and 2014 were $30 million and $24 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $59 million and $31 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets. SWEPCo’s investment in DHLC was: September 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) Capital Contribution from SWEPCo $ 7,643 $ 7,643 $ 7,643 $ 7,643 Retained Earnings 5,950 5,950 3,819 3,819 SWEPCo's Guarantee of Debt — 95,180 (a) — 104,334 (a) Total Investment in DHLC $ 13,593 $ 108,773 $ 11,462 $ 115,796 (a) Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $40 million and $56 million in 2015 and 2014 , respectively. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 63,687 $ 50,143 $ 164,657 $ 154,239 I&M 37,506 30,613 102,141 92,686 OPCo 48,471 41,212 128,608 120,696 PSO 29,851 24,317 77,817 71,646 SWEPCo 39,150 32,787 102,564 98,528 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: September 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 23,783 $ 23,783 $ 30,692 $ 30,692 I&M 13,676 13,676 22,480 22,480 OPCo 18,770 18,770 24,695 24,695 PSO 10,713 10,713 15,338 15,338 SWEPCo 14,295 14,295 20,772 20,772 AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo and AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligation of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the three months ended September 30, 2015 and 2014 were $67 million and $67 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $182 million and $202 million , respectively. The carrying amount of I&M's liabilities associated with AEGCo as of September 30, 2015 and December 31, 2014 was $17 million and $20 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo's lease, see "Rockport Lease" section of Note 13 in the 2014 Annual Report. |
Southwestern Electric Power Co [Member] | |
Variable Interest Entities | VARIABLE INTEREST ENTITIES The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding. In addition, the Registrant Subsidiaries have not provided material financial or other support to any of these entities that was not previously contractually required. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M holds a significant variable interest in AEGCo. Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended September 30, 2015 and 2014 were $41 million and $41 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $124 million and $121 million , respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets. The balances below represent the assets and liabilities of Sabine that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Sabine ASSETS 2015 2014 Current Assets $ 61,025 $ 67,981 Net Property, Plant and Equipment 143,815 145,491 Other Noncurrent Assets 60,160 51,578 Total Assets $ 265,000 $ 265,050 LIABILITIES AND EQUITY Current Liabilities $ 40,311 $ 36,286 Noncurrent Liabilities 224,371 228,349 Equity 318 415 Total Liabilities and Equity $ 265,000 $ 265,050 I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended September 30, 2015 and 2014 were $29 million and $28 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $86 million and $84 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months . Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets. The balances below represent the assets and liabilities of DCC Fuel that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) DCC Fuel ASSETS 2015 2014 Current Assets $ 104,273 $ 97,361 Net Property, Plant and Equipment 193,447 158,121 Other Noncurrent Assets 99,811 79,705 Total Assets $ 397,531 $ 335,187 LIABILITIES AND EQUITY Current Liabilities $ 98,173 $ 86,026 Noncurrent Liabilities 299,358 249,161 Total Liabilities and Equity $ 397,531 $ 335,187 Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $187 million and $232 million as of September 30, 2015 and December 31, 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $92 million and $110 million as of September 30, 2015 and December 31, 2014 , respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s condensed balance sheets. The balances below represent the assets and liabilities of Ohio Phase-in-Recovery Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. OHIO POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Ohio Phase-In Recovery Funding ASSETS 2015 2014 Current Assets $ 20,236 $ 32,676 Other Noncurrent Assets (a) 175,189 209,922 Total Assets $ 195,425 $ 242,598 LIABILITIES AND EQUITY Current Liabilities $ 46,592 $ 47,099 Noncurrent Liabilities 147,496 194,162 Equity 1,337 1,337 Total Liabilities and Equity $ 195,425 $ 242,598 (a) Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $81 million and $97 million , respectively. Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $345 million and $368 million as of September 30, 2015 and December 31, 2014 , respectively, and are included in Long-term Debt Due Within One Year - Nonaffiliated and Long-term Debt - Nonaffiliated on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $333 million and $350 million as of September 30, 2015 and December 31, 2014 , respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s condensed balance sheets. The balances below represent the assets and liabilities of Appalachian Consumer Rate Relief Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. APPALACHIAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Appalachian Consumer Rate Relief Funding ASSETS 2015 2014 Current Assets $ 10,914 $ 18,099 Other Noncurrent Assets (a) 341,127 358,264 Total Assets $ 352,041 $ 376,363 LIABILITIES AND EQUITY Current Liabilities $ 24,617 $ 26,809 Noncurrent Liabilities 325,534 347,652 Equity 1,890 1,902 Total Liabilities and Equity $ 352,041 $ 376,363 (a) Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $4 million and $4 million , respectively. DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended September 30, 2015 and 2014 were $30 million and $24 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $59 million and $31 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets. SWEPCo’s investment in DHLC was: September 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) Capital Contribution from SWEPCo $ 7,643 $ 7,643 $ 7,643 $ 7,643 Retained Earnings 5,950 5,950 3,819 3,819 SWEPCo's Guarantee of Debt — 95,180 (a) — 104,334 (a) Total Investment in DHLC $ 13,593 $ 108,773 $ 11,462 $ 115,796 (a) Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $40 million and $56 million in 2015 and 2014 , respectively. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 63,687 $ 50,143 $ 164,657 $ 154,239 I&M 37,506 30,613 102,141 92,686 OPCo 48,471 41,212 128,608 120,696 PSO 29,851 24,317 77,817 71,646 SWEPCo 39,150 32,787 102,564 98,528 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: September 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 23,783 $ 23,783 $ 30,692 $ 30,692 I&M 13,676 13,676 22,480 22,480 OPCo 18,770 18,770 24,695 24,695 PSO 10,713 10,713 15,338 15,338 SWEPCo 14,295 14,295 20,772 20,772 AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo and AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligation of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the three months ended September 30, 2015 and 2014 were $67 million and $67 million , respectively, and for the nine months ended September 30, 2015 and 2014 were $182 million and $202 million , respectively. The carrying amount of I&M's liabilities associated with AEGCo as of September 30, 2015 and December 31, 2014 was $17 million and $20 million , respectively. Management estimates the maximum exposure of loss to be equal to the amount of such liability. For additional information regarding AEGCo's lease, see "Rockport Lease" section of Note 13 in the 2014 Annual Report. |
Property, Plant and Equipment P
Property, Plant and Equipment Property, Plant and Equipment | 9 Months Ended |
Sep. 30, 2015 | |
Property, Plant and Equipment Disclosure [Text Block] | 14 . PROPERTY, PLANT AND EQUIPMENT Asset Retirement Obligations (ARO) We record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for our legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities, as well as for nuclear decommissioning of our Cook Plant. We have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use. We do not estimate the retirement for such easements because we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements, which is not expected. We recorded an increase in our asset retirement obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the aggregate carrying amount of ARO, including a $95 million second quarter increase and other adjustments recorded in the third quarter: Carrying Amount of ARO (in millions) ARO as of December 31, 2014 $ 2,019 Accretion Expense 76 Liabilities Incurred 48 Liabilities Settled (a) (126 ) Revisions in Cash Flow Estimates (b) 30 ARO as of September 30, 2015 $ 2,047 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the "Muskingum River Plant" section of Note 6 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. As of September 30, 2015 and December 31, 2014 , our ARO liability included $1.31 billion and $1.27 billion , respectively, for nuclear decommissioning of the Cook Plant. As of September 30, 2015 and December 31, 2014 , the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $1.74 billion and $1.79 billion , respectively, and are recorded in Spent Nuclear Fuel and Decommissioning Trusts on the condensed balance sheets. |
Appalachian Power Co [Member] | |
Property, Plant and Equipment Disclosure [Text Block] | PROPERTY, PLANT AND EQUIPMENT Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. As of September 30, 2015 and December 31, 2014 , I&M's ARO liability for nuclear decommissioning of the Cook Plant was $1.31 billion and $1.27 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M's condensed balance sheets. As of September 30, 2015 and December 31, 2014 , the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.74 billion and $1.79 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's condensed balance sheets. The Registrant Subsidiaries recorded an increase in asset retirement obligations in the second quarter of 2015, partially related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the aggregate carrying amounts of ARO by Registrant Subsidiary: ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates September 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 6,239 $ — $ (23,471 ) $ 16,977 $ 148,122 I&M (a)(b)(d) 1,342,549 47,918 — (3,977 ) 5,638 1,392,128 OPCo (d)(e) 1,361 62 — (8 ) — 1,415 PSO (a)(d) 38,020 1,923 5,336 (125 ) 1,916 47,070 SWEPCo (a)(c)(d) 94,394 4,299 12,191 (3,358 ) 6,349 113,875 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule. |
Indiana Michigan Power Co [Member] | |
Property, Plant and Equipment Disclosure [Text Block] | PROPERTY, PLANT AND EQUIPMENT Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. As of September 30, 2015 and December 31, 2014 , I&M's ARO liability for nuclear decommissioning of the Cook Plant was $1.31 billion and $1.27 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M's condensed balance sheets. As of September 30, 2015 and December 31, 2014 , the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.74 billion and $1.79 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's condensed balance sheets. The Registrant Subsidiaries recorded an increase in asset retirement obligations in the second quarter of 2015, partially related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the aggregate carrying amounts of ARO by Registrant Subsidiary: ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates September 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 6,239 $ — $ (23,471 ) $ 16,977 $ 148,122 I&M (a)(b)(d) 1,342,549 47,918 — (3,977 ) 5,638 1,392,128 OPCo (d)(e) 1,361 62 — (8 ) — 1,415 PSO (a)(d) 38,020 1,923 5,336 (125 ) 1,916 47,070 SWEPCo (a)(c)(d) 94,394 4,299 12,191 (3,358 ) 6,349 113,875 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule. |
Ohio Power Co [Member] | |
Property, Plant and Equipment Disclosure [Text Block] | PROPERTY, PLANT AND EQUIPMENT Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. As of September 30, 2015 and December 31, 2014 , I&M's ARO liability for nuclear decommissioning of the Cook Plant was $1.31 billion and $1.27 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M's condensed balance sheets. As of September 30, 2015 and December 31, 2014 , the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.74 billion and $1.79 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's condensed balance sheets. The Registrant Subsidiaries recorded an increase in asset retirement obligations in the second quarter of 2015, partially related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the aggregate carrying amounts of ARO by Registrant Subsidiary: ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates September 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 6,239 $ — $ (23,471 ) $ 16,977 $ 148,122 I&M (a)(b)(d) 1,342,549 47,918 — (3,977 ) 5,638 1,392,128 OPCo (d)(e) 1,361 62 — (8 ) — 1,415 PSO (a)(d) 38,020 1,923 5,336 (125 ) 1,916 47,070 SWEPCo (a)(c)(d) 94,394 4,299 12,191 (3,358 ) 6,349 113,875 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule. |
Public Service Co Of Oklahoma [Member] | |
Property, Plant and Equipment Disclosure [Text Block] | PROPERTY, PLANT AND EQUIPMENT Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. As of September 30, 2015 and December 31, 2014 , I&M's ARO liability for nuclear decommissioning of the Cook Plant was $1.31 billion and $1.27 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M's condensed balance sheets. As of September 30, 2015 and December 31, 2014 , the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.74 billion and $1.79 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's condensed balance sheets. The Registrant Subsidiaries recorded an increase in asset retirement obligations in the second quarter of 2015, partially related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the aggregate carrying amounts of ARO by Registrant Subsidiary: ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates September 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 6,239 $ — $ (23,471 ) $ 16,977 $ 148,122 I&M (a)(b)(d) 1,342,549 47,918 — (3,977 ) 5,638 1,392,128 OPCo (d)(e) 1,361 62 — (8 ) — 1,415 PSO (a)(d) 38,020 1,923 5,336 (125 ) 1,916 47,070 SWEPCo (a)(c)(d) 94,394 4,299 12,191 (3,358 ) 6,349 113,875 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule. |
Southwestern Electric Power Co [Member] | |
Property, Plant and Equipment Disclosure [Text Block] | PROPERTY, PLANT AND EQUIPMENT Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. As of September 30, 2015 and December 31, 2014 , I&M's ARO liability for nuclear decommissioning of the Cook Plant was $1.31 billion and $1.27 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M's condensed balance sheets. As of September 30, 2015 and December 31, 2014 , the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.74 billion and $1.79 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's condensed balance sheets. The Registrant Subsidiaries recorded an increase in asset retirement obligations in the second quarter of 2015, partially related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the aggregate carrying amounts of ARO by Registrant Subsidiary: ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates September 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 6,239 $ — $ (23,471 ) $ 16,977 $ 148,122 I&M (a)(b)(d) 1,342,549 47,918 — (3,977 ) 5,638 1,392,128 OPCo (d)(e) 1,361 62 — (8 ) — 1,415 PSO (a)(d) 38,020 1,923 5,336 (125 ) 1,916 47,070 SWEPCo (a)(c)(d) 94,394 4,299 12,191 (3,358 ) 6,349 113,875 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule. |
Disposition Plant Severance
Disposition Plant Severance | 9 Months Ended |
Sep. 30, 2015 | |
Cost Reduction Programs | DISPOSITION PLANT SEVERANCE AEP retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The disposition plant severance activity for the nine months ended September 30, 2015 is described in the following table: Disposition Plant Severance Activity (in millions) Balance as of December 31, 2014 $ 29 Incurred 3 Settled (21 ) Adjustments — Balance as of September 30, 2015 $ 11 We recorded a charge of $29 million to Other Operation expense in 2014 primarily related to employees at the disposition plants. These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. Of the cumulative expense, approximately 32% was within the Generation & Marketing segment and 68% was within the Vertically Integrated Utilities segment. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. We incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. We do not expect additional severance costs to be incurred related to this initiative. |
Appalachian Power Co [Member] | |
Cost Reduction Programs | DISPOSITION PLANT SEVERANCE Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrant Subsidiaries' disposition plant severance activity for the nine months ended September 30, 2015 is described in the following table: Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments September 30, 2015 (in thousands) APCo $ 9,304 $ (6 ) $ 849 $ (6,385 ) (a) $ (119 ) $ 3,643 I&M 8,023 (2 ) 351 (5,110 ) — 3,262 PSO 134 (3 ) 415 (121 ) — 425 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. The Registrant Subsidiaries recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amount incurred in 2014 by Registrant Subsidiary was as follows: Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. The Registrant Subsidiaries incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative. |
Indiana Michigan Power Co [Member] | |
Cost Reduction Programs | DISPOSITION PLANT SEVERANCE Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrant Subsidiaries' disposition plant severance activity for the nine months ended September 30, 2015 is described in the following table: Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments September 30, 2015 (in thousands) APCo $ 9,304 $ (6 ) $ 849 $ (6,385 ) (a) $ (119 ) $ 3,643 I&M 8,023 (2 ) 351 (5,110 ) — 3,262 PSO 134 (3 ) 415 (121 ) — 425 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. The Registrant Subsidiaries recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amount incurred in 2014 by Registrant Subsidiary was as follows: Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. The Registrant Subsidiaries incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative. |
Ohio Power Co [Member] | |
Cost Reduction Programs | DISPOSITION PLANT SEVERANCE Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrant Subsidiaries' disposition plant severance activity for the nine months ended September 30, 2015 is described in the following table: Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments September 30, 2015 (in thousands) APCo $ 9,304 $ (6 ) $ 849 $ (6,385 ) (a) $ (119 ) $ 3,643 I&M 8,023 (2 ) 351 (5,110 ) — 3,262 PSO 134 (3 ) 415 (121 ) — 425 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. The Registrant Subsidiaries recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amount incurred in 2014 by Registrant Subsidiary was as follows: Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. The Registrant Subsidiaries incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative. |
Public Service Co Of Oklahoma [Member] | |
Cost Reduction Programs | DISPOSITION PLANT SEVERANCE Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrant Subsidiaries' disposition plant severance activity for the nine months ended September 30, 2015 is described in the following table: Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments September 30, 2015 (in thousands) APCo $ 9,304 $ (6 ) $ 849 $ (6,385 ) (a) $ (119 ) $ 3,643 I&M 8,023 (2 ) 351 (5,110 ) — 3,262 PSO 134 (3 ) 415 (121 ) — 425 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. The Registrant Subsidiaries recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amount incurred in 2014 by Registrant Subsidiary was as follows: Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. The Registrant Subsidiaries incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative. |
Southwestern Electric Power Co [Member] | |
Cost Reduction Programs | DISPOSITION PLANT SEVERANCE Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrant Subsidiaries' disposition plant severance activity for the nine months ended September 30, 2015 is described in the following table: Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments September 30, 2015 (in thousands) APCo $ 9,304 $ (6 ) $ 849 $ (6,385 ) (a) $ (119 ) $ 3,643 I&M 8,023 (2 ) 351 (5,110 ) — 3,262 PSO 134 (3 ) 415 (121 ) — 425 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. The Registrant Subsidiaries recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amount incurred in 2014 by Registrant Subsidiary was as follows: Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. The Registrant Subsidiaries incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative. |
Significant Accounting Matters
Significant Accounting Matters (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Basis of Accounting | General The unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2014 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 20, 2015 . |
Revenue Recognition | Revenue Recognition Electricity Supply and Delivery Activities - Transactions with PJM Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. For regulated and nonregulated operations, we recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. APCo, I&M, KPCo and WPCo sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary’s retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenue on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement on January 1, 2014, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices. AEP’s nonregulated subsidiaries also purchase power from PJM and sell power to PJM. With the exception of certain dedicated load bilateral power supply contracts, these transactions are reported as gross purchases and sales. |
Earnings Per Share | Earnings Per Share (EPS) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. |
Appalachian Power Co [Member] | |
Basis of Accounting | General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 . |
Indiana Michigan Power Co [Member] | |
Basis of Accounting | General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 . |
Ohio Power Co [Member] | |
Basis of Accounting | General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 . |
Public Service Co Of Oklahoma [Member] | |
Basis of Accounting | General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 . |
Southwestern Electric Power Co [Member] | |
Basis of Accounting | General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 . |
Disposition, Assets and Liabi25
Disposition, Assets and Liabilities Held for Sale and Discontinued Operations (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Discontinued Operations Policy | Management periodically assesses the overall AEP business model and makes decisions regarding our continued support and funding of our various businesses and operations. When it is determined that we will seek to exit a particular business or activity and we have met the accounting requirements for reclassification, we will reclassify the operations of those businesses or operations as discontinued operations. The assets and liabilities of these discontinued operations are classified as Assets Held for Sale and Liabilities Held for Sale until the time they are sold. |
Derivatives and Hedging (Polici
Derivatives and Hedging (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Derivatives and Hedging | Credit Risk We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. We use Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. When we use standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs), we are obligated to post an additional amount of collateral for a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads and guaranties for contractual obligations if our credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP and its subsidiaries have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. Fair Value Hedging Strategies We enter into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. Cash Flow Hedging Strategies We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and energy purchases. We do not hedge all commodity price risk. Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility. We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. We do not hedge all fuel price risk. We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate. We also enter into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. Our forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure. At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. We do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of our derivative instruments, we also apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with our estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of our risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles. In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million . On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis. Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, we designate a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our condensed statements of income. We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS We are exposed to certain market risks as a major power producer and participant in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates. We manage these risks using derivative instruments. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies Our strategy surrounding the use of derivative instruments primarily focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. Our risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact. To accomplish our objectives, we primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. We enter into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with our energy business. We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities. We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur. The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets until the period the hedged item affects Net Income. We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power and natural gas designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged. |
Appalachian Power Co [Member] | |
Derivatives and Hedging | Cash Flow Hedging Strategies AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrant Subsidiaries do not hedge all commodity price risk. The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk. AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrant Subsidiaries do not hedge all interest rate exposure. At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. Credit Risk AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million . On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. |
Indiana Michigan Power Co [Member] | |
Derivatives and Hedging | Credit Risk AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million . On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Cash Flow Hedging Strategies AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrant Subsidiaries do not hedge all commodity price risk. The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk. AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrant Subsidiaries do not hedge all interest rate exposure. At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. |
Ohio Power Co [Member] | |
Derivatives and Hedging | The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million . On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. Credit Risk AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. Cash Flow Hedging Strategies AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrant Subsidiaries do not hedge all commodity price risk. The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk. AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrant Subsidiaries do not hedge all interest rate exposure. At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. |
Public Service Co Of Oklahoma [Member] | |
Derivatives and Hedging | Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. Cash Flow Hedging Strategies AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrant Subsidiaries do not hedge all commodity price risk. The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk. AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrant Subsidiaries do not hedge all interest rate exposure. At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. Credit Risk AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million . On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. |
Southwestern Electric Power Co [Member] | |
Derivatives and Hedging | The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Revenues or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. Cash Flow Hedging Strategies AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrant Subsidiaries do not hedge all commodity price risk. The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. In March 2014, these contracts were grouped as "Commodity" with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk. AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrant Subsidiaries do not hedge all interest rate exposure. At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract's term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. Credit Risk AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Collateral Triggering Events Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million . On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the condensed statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the condensed statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” |
Fair Value Measurements (Polici
Fair Value Measurements (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Valuation Techniques | Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For our commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated. We typically obtain multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, we average the quoted bid and ask prices. In certain circumstances, we may discard a broker quote if it is a clear outlier. We use a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, we include these locations within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of our contracts being classified as Level 3 is the inability to substantiate our energy price curves in the market. A significant portion of our Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. We utilize our trustee’s external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts. Our investment managers review and validate the prices utilized by the trustee to determine fair value. We perform our own valuation testing to verify the fair values of the securities. We receive audit reports of our trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange. |
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal | Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP or its affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. We maintain trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in the trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. |
Fair Value Assets and Liabilities Measured on Recurring Basis | As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in our valuation techniques. |
Appalachian Power Co [Member] | |
Valuation Techniques | Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. |
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal | Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP or its affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. |
Fair Value Assets and Liabilities Measured on Recurring Basis | As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. |
Indiana Michigan Power Co [Member] | |
Valuation Techniques | Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. |
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal | Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP or its affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. |
Fair Value Assets and Liabilities Measured on Recurring Basis | As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. |
Ohio Power Co [Member] | |
Valuation Techniques | Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. |
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal | Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP or its affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. |
Fair Value Assets and Liabilities Measured on Recurring Basis | As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. |
Public Service Co Of Oklahoma [Member] | |
Valuation Techniques | Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. |
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal | Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP or its affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. |
Fair Value Assets and Liabilities Measured on Recurring Basis | As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. |
Southwestern Electric Power Co [Member] | |
Valuation Techniques | Fair Value Hierarchy and Valuation Techniques The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. |
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal | Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP or its affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. |
Fair Value Assets and Liabilities Measured on Recurring Basis | As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. |
Income Taxes (Policies)
Income Taxes (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Income Tax Policy | AEP System Tax Allocation Agreement We, along with our subsidiaries, file a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. |
Appalachian Power Co [Member] | |
Income Tax Policy | AEP System Tax Allocation Agreement The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. |
Indiana Michigan Power Co [Member] | |
Income Tax Policy | AEP System Tax Allocation Agreement The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. |
Ohio Power Co [Member] | |
Income Tax Policy | AEP System Tax Allocation Agreement The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. |
Public Service Co Of Oklahoma [Member] | |
Income Tax Policy | AEP System Tax Allocation Agreement The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. |
Southwestern Electric Power Co [Member] | |
Income Tax Policy | AEP System Tax Allocation Agreement The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. |
Variable Interest Entities (Pol
Variable Interest Entities (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Variable Interest Entities | The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE’s variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. We believe that significant assumptions and judgments were applied consistently. |
Appalachian Power Co [Member] | |
Variable Interest Entities | The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. |
Indiana Michigan Power Co [Member] | |
Variable Interest Entities | The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. |
Ohio Power Co [Member] | |
Variable Interest Entities | The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. |
Public Service Co Of Oklahoma [Member] | |
Variable Interest Entities | The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. |
Southwestern Electric Power Co [Member] | |
Variable Interest Entities | The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. |
Property, Plant and Equipment30
Property, Plant and Equipment Property, Plant and Equipment (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Asset Retirement Obligations, Policy | Asset Retirement Obligations (ARO) We record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for our legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities, as well as for nuclear decommissioning of our Cook Plant. We have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use. We do not estimate the retirement for such easements because we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements, which is not expected. |
Appalachian Power Co [Member] | |
Asset Retirement Obligations, Policy | Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. |
Indiana Michigan Power Co [Member] | |
Asset Retirement Obligations, Policy | Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. |
Ohio Power Co [Member] | |
Asset Retirement Obligations, Policy | Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. |
Public Service Co Of Oklahoma [Member] | |
Asset Retirement Obligations, Policy | Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. |
Southwestern Electric Power Co [Member] | |
Asset Retirement Obligations, Policy | Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. |
Significant Accounting Matter31
Significant Accounting Matters (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Basic and Diluted EPS Calculations | Three Months Ended September 30, 2015 2014 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 512 $ 483 Less: Net Income Attributable to Noncontrolling Interests 1 1 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 511 $ 482 Weighted Average Number of Basic Shares Outstanding 490.6 $ 1.04 488.9 $ 0.99 Weighted Average Dilutive Effect of Restricted Stock Units 0.2 — 0.1 — Weighted Average Number of Diluted Shares Outstanding 490.8 $ 1.04 489.0 $ 0.99 Nine Months Ended September 30, 2015 2014 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 1,564 $ 1,430 Less: Net Income Attributable to Noncontrolling Interests 4 3 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 1,560 $ 1,427 Weighted Average Number of Basic Shares Outstanding 490.2 $ 3.18 488.4 $ 2.92 Weighted Average Dilutive Effect of Restricted Stock Units 0.2 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 490.4 $ 3.18 488.6 $ 2.92 |
Supplementary Information | Nine Months Ended September 30, Cash Flow Information 2015 2014 (in millions) Cash Paid (Received) for: Cash Paid for Interest, Net of Capitalized Amounts $ 639 $ 649 Net Cash Paid for Income Taxes 116 109 Noncash Investing and Financing Activities: Noncash Acquisitions Under Capital Leases 97 80 Construction Expenditures Included in Current Liabilities as of September 30, 579 515 Construction Expenditures Included in Noncurrent Liabilities as of September 30, 66 — Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, 31 — |
Comprehensive Income (Tables)
Comprehensive Income (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Changes in Accumulated Other Comprehensive Income by Component | Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2015 $ (5 ) $ (18 ) $ 8 $ (87 ) $ (102 ) Change in Fair Value Recognized in AOCI (3 ) — (1 ) — (4 ) Amounts Reclassified from AOCI (3 ) — — — (3 ) Net Current Period Other Comprehensive Loss (6 ) — (1 ) — (7 ) Balance in AOCI as of September 30, 2015 $ (11 ) $ (18 ) $ 7 $ (87 ) $ (109 ) Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of June 30, 2014 $ 6 $ (21 ) $ 8 $ (97 ) $ (104 ) Change in Fair Value Recognized in AOCI 3 — — — 3 Amounts Reclassified from AOCI (6 ) 1 — 1 (4 ) Net Current Period Other Comprehensive Income (Loss) (3 ) 1 — 1 (1 ) Balance in AOCI as of September 30, 2014 $ 3 $ (20 ) $ 8 $ (96 ) $ (105 ) Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 1 $ (19 ) $ 8 $ (93 ) $ (103 ) Change in Fair Value Recognized in AOCI (2 ) — (1 ) — (3 ) Amounts Reclassified from AOCI (10 ) 1 — 1 (8 ) Net Current Period Other Comprehensive Income (Loss) (12 ) 1 (1 ) 1 (11 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — 5 5 Balance in AOCI as of September 30, 2015 $ (11 ) $ (18 ) $ 7 $ (87 ) $ (109 ) Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (23 ) $ 7 $ (99 ) $ (115 ) Change in Fair Value Recognized in AOCI (8 ) — 1 — (7 ) Amounts Reclassified from AOCI 11 3 — 3 17 Net Current Period Other Comprehensive Income 3 3 1 3 10 Balance in AOCI as of September 30, 2014 $ 3 $ (20 ) $ 8 $ (96 ) $ (105 ) |
Reclassifications from Accumulated Other Comprehensive Income | Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Generation & Marketing Revenues $ (19 ) $ — Purchased Electricity for Resale 14 (9 ) Subtotal – Commodity (5 ) (9 ) Interest Rate and Foreign Currency: Interest Expense — 2 Subtotal – Interest Rate and Foreign Currency — 2 Reclassifications from AOCI, before Income Tax (Expense) Credit (5 ) (7 ) Income Tax (Expense) Credit (2 ) (2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (3 ) (5 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (5 ) (5 ) Amortization of Actuarial (Gains)/Losses 5 7 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2 Income Tax (Expense) Credit — 1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (3 ) $ (4 ) Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Generation & Marketing Revenues $ (36 ) $ — Purchased Electricity for Resale 20 20 Regulatory Assets/(Liabilities), Net (a) — (3 ) Subtotal – Commodity (16 ) 17 Interest Rate and Foreign Currency: Interest Expense 1 6 Subtotal – Interest Rate and Foreign Currency 1 6 Reclassifications from AOCI, before Income Tax (Expense) Credit (15 ) 23 Income Tax (Expense) Credit (6 ) 9 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (9 ) 14 Pension and OPEB Amortization of Prior Service Cost (Credit) (15 ) (15 ) Amortization of Actuarial (Gains)/Losses 16 21 Reclassifications from AOCI, before Income Tax (Expense) Credit 1 6 Income Tax (Expense) Credit — 3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1 3 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (8 ) $ 17 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Appalachian Power Co [Member] | |
Changes in Accumulated Other Comprehensive Income by Component | APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — (222 ) (458 ) (680 ) Net Current Period Other Comprehensive Loss — (222 ) (458 ) (680 ) Balance in AOCI as of September 30, 2015 $ — $ 3,805 $ (238 ) $ 3,567 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 170 (333 ) (163 ) Net Current Period Other Comprehensive Income (Loss) — 170 (333 ) (163 ) Balance in AOCI as of September 30, 2014 $ — $ 3,766 $ (1,232 ) $ 2,534 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 3,896 $ 1,136 $ 5,032 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — (91 ) (1,374 ) (1,465 ) Net Current Period Other Comprehensive Loss — (91 ) (1,374 ) (1,465 ) Balance in AOCI as of September 30, 2015 $ — $ 3,805 $ (238 ) $ 3,567 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 94 $ 3,090 $ (233 ) $ 2,951 Change in Fair Value Recognized in AOCI 1,686 — — 1,686 Amounts Reclassified from AOCI (1,780 ) 676 (999 ) (2,103 ) Net Current Period Other Comprehensive Income (Loss) (94 ) 676 (999 ) (417 ) Balance in AOCI as of September 30, 2014 $ — $ 3,766 $ (1,232 ) $ 2,534 |
Reclassifications from Accumulated Other Comprehensive Income | APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (342 ) 262 Subtotal – Interest Rate and Foreign Currency (342 ) 262 Reclassifications from AOCI, before Income Tax (Expense) Credit (342 ) 262 Income Tax (Expense) Credit (120 ) 92 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (222 ) 170 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,282 ) (1,281 ) Amortization of Actuarial (Gains)/Losses 577 769 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (512 ) Income Tax (Expense) Credit (247 ) (179 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (680 ) $ (163 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense (140 ) 1,042 Subtotal – Interest Rate and Foreign Currency (140 ) 1,042 Reclassifications from AOCI, before Income Tax (Expense) Credit (140 ) (1,696 ) Income Tax (Expense) Credit (49 ) (592 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (91 ) (1,104 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (3,847 ) (3,846 ) Amortization of Actuarial (Gains)/Losses 1,733 2,309 Reclassifications from AOCI, before Income Tax (Expense) Credit (2,114 ) (1,537 ) Income Tax (Expense) Credit (740 ) (538 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1,374 ) (999 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,465 ) $ (2,103 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 412 631 Subtotal – Interest Rate and Foreign Currency 412 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 412 631 Income Tax (Expense) Credit 145 221 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 267 410 Pension and OPEB Amortization of Prior Service Cost (Credit) (198 ) (200 ) Amortization of Actuarial (Gains)/Losses 215 264 Reclassifications from AOCI, before Income Tax (Expense) Credit 17 64 Income Tax (Expense) Credit 6 22 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11 42 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 452 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 1,234 1,893 Subtotal – Interest Rate and Foreign Currency 1,234 1,893 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,234 84 Income Tax (Expense) Credit 432 29 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 802 55 Pension and OPEB Amortization of Prior Service Cost (Credit) (596 ) (597 ) Amortization of Actuarial (Gains)/Losses 647 791 Reclassifications from AOCI, before Income Tax (Expense) Credit 51 194 Income Tax (Expense) Credit 18 66 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 33 128 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 835 $ 183 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (4 ) (3 ) Interest Expense (526 ) (524 ) Subtotal – Interest Rate and Foreign Currency (530 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (530 ) (527 ) Income Tax (Expense) Credit (186 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (344 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (10 ) (9 ) Interest Expense (1,574 ) (1,572 ) Subtotal – Interest Rate and Foreign Currency (1,584 ) (1,581 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,584 ) (1,743 ) Income Tax (Expense) Credit (554 ) (609 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,030 ) $ (1,134 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (291 ) (292 ) Subtotal – Interest Rate and Foreign Currency (291 ) (292 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (291 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (189 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (875 ) (876 ) Subtotal – Interest Rate and Foreign Currency (875 ) (876 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (875 ) (964 ) Income Tax (Expense) Credit (306 ) (338 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (569 ) $ (626 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 665 872 Subtotal – Interest Rate and Foreign Currency 665 872 Reclassifications from AOCI, before Income Tax (Expense) Credit 665 872 Income Tax (Expense) Credit 233 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 432 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (468 ) (478 ) Amortization of Actuarial (Gains)/Losses 99 118 Reclassifications from AOCI, before Income Tax (Expense) Credit (369 ) (360 ) Income Tax (Expense) Credit (129 ) (125 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (240 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 192 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 2,409 2,616 Subtotal – Interest Rate and Foreign Currency 2,409 2,616 Reclassifications from AOCI, before Income Tax (Expense) Credit 2,409 2,515 Income Tax (Expense) Credit 843 879 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,566 1,636 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,402 ) (1,433 ) Amortization of Actuarial (Gains)/Losses 296 351 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,106 ) (1,082 ) Income Tax (Expense) Credit (387 ) (378 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (719 ) (704 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 847 $ 932 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Indiana Michigan Power Co [Member] | |
Changes in Accumulated Other Comprehensive Income by Component | I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 267 11 278 Net Current Period Other Comprehensive Income — 267 11 278 Balance in AOCI as of September 30, 2015 $ — $ (13,604 ) $ 79 $ (13,525 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 410 42 452 Net Current Period Other Comprehensive Income — 410 42 452 Balance in AOCI as of September 30, 2014 $ — $ (14,745 ) $ 549 $ (14,196 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (14,406 ) $ 46 $ (14,360 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 802 33 835 Net Current Period Other Comprehensive Income — 802 33 835 Balance in AOCI as of September 30, 2015 $ — $ (13,604 ) $ 79 $ (13,525 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 46 $ (15,976 ) $ 421 $ (15,509 ) Change in Fair Value Recognized in AOCI 1,130 — — 1,130 Amounts Reclassified from AOCI (1,176 ) 1,231 128 183 Net Current Period Other Comprehensive Income (Loss) (46 ) 1,231 128 1,313 Balance in AOCI as of September 30, 2014 $ — $ (14,745 ) $ 549 $ (14,196 ) |
Reclassifications from Accumulated Other Comprehensive Income | APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (342 ) 262 Subtotal – Interest Rate and Foreign Currency (342 ) 262 Reclassifications from AOCI, before Income Tax (Expense) Credit (342 ) 262 Income Tax (Expense) Credit (120 ) 92 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (222 ) 170 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,282 ) (1,281 ) Amortization of Actuarial (Gains)/Losses 577 769 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (512 ) Income Tax (Expense) Credit (247 ) (179 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (680 ) $ (163 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense (140 ) 1,042 Subtotal – Interest Rate and Foreign Currency (140 ) 1,042 Reclassifications from AOCI, before Income Tax (Expense) Credit (140 ) (1,696 ) Income Tax (Expense) Credit (49 ) (592 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (91 ) (1,104 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (3,847 ) (3,846 ) Amortization of Actuarial (Gains)/Losses 1,733 2,309 Reclassifications from AOCI, before Income Tax (Expense) Credit (2,114 ) (1,537 ) Income Tax (Expense) Credit (740 ) (538 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1,374 ) (999 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,465 ) $ (2,103 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 412 631 Subtotal – Interest Rate and Foreign Currency 412 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 412 631 Income Tax (Expense) Credit 145 221 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 267 410 Pension and OPEB Amortization of Prior Service Cost (Credit) (198 ) (200 ) Amortization of Actuarial (Gains)/Losses 215 264 Reclassifications from AOCI, before Income Tax (Expense) Credit 17 64 Income Tax (Expense) Credit 6 22 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11 42 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 452 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 1,234 1,893 Subtotal – Interest Rate and Foreign Currency 1,234 1,893 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,234 84 Income Tax (Expense) Credit 432 29 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 802 55 Pension and OPEB Amortization of Prior Service Cost (Credit) (596 ) (597 ) Amortization of Actuarial (Gains)/Losses 647 791 Reclassifications from AOCI, before Income Tax (Expense) Credit 51 194 Income Tax (Expense) Credit 18 66 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 33 128 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 835 $ 183 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (4 ) (3 ) Interest Expense (526 ) (524 ) Subtotal – Interest Rate and Foreign Currency (530 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (530 ) (527 ) Income Tax (Expense) Credit (186 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (344 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (10 ) (9 ) Interest Expense (1,574 ) (1,572 ) Subtotal – Interest Rate and Foreign Currency (1,584 ) (1,581 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,584 ) (1,743 ) Income Tax (Expense) Credit (554 ) (609 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,030 ) $ (1,134 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (291 ) (292 ) Subtotal – Interest Rate and Foreign Currency (291 ) (292 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (291 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (189 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (875 ) (876 ) Subtotal – Interest Rate and Foreign Currency (875 ) (876 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (875 ) (964 ) Income Tax (Expense) Credit (306 ) (338 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (569 ) $ (626 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 665 872 Subtotal – Interest Rate and Foreign Currency 665 872 Reclassifications from AOCI, before Income Tax (Expense) Credit 665 872 Income Tax (Expense) Credit 233 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 432 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (468 ) (478 ) Amortization of Actuarial (Gains)/Losses 99 118 Reclassifications from AOCI, before Income Tax (Expense) Credit (369 ) (360 ) Income Tax (Expense) Credit (129 ) (125 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (240 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 192 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 2,409 2,616 Subtotal – Interest Rate and Foreign Currency 2,409 2,616 Reclassifications from AOCI, before Income Tax (Expense) Credit 2,409 2,515 Income Tax (Expense) Credit 843 879 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,566 1,636 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,402 ) (1,433 ) Amortization of Actuarial (Gains)/Losses 296 351 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,106 ) (1,082 ) Income Tax (Expense) Credit (387 ) (378 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (719 ) (704 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 847 $ 932 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Ohio Power Co [Member] | |
Changes in Accumulated Other Comprehensive Income by Component | OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (344 ) (344 ) Net Current Period Other Comprehensive Loss — (344 ) (344 ) Balance in AOCI as of September 30, 2015 $ — $ 4,572 $ 4,572 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of September 30, 2014 $ — $ 5,945 $ 5,945 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 5,602 $ 5,602 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (1,030 ) (1,030 ) Net Current Period Other Comprehensive Loss — (1,030 ) (1,030 ) Balance in AOCI as of September 30, 2015 $ — $ 4,572 $ 4,572 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2013 $ 105 $ 6,974 $ 7,079 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (105 ) (1,029 ) (1,134 ) Net Current Period Other Comprehensive Loss (105 ) (1,029 ) (1,134 ) Balance in AOCI as of September 30, 2014 $ — $ 5,945 $ 5,945 |
Reclassifications from Accumulated Other Comprehensive Income | APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (342 ) 262 Subtotal – Interest Rate and Foreign Currency (342 ) 262 Reclassifications from AOCI, before Income Tax (Expense) Credit (342 ) 262 Income Tax (Expense) Credit (120 ) 92 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (222 ) 170 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,282 ) (1,281 ) Amortization of Actuarial (Gains)/Losses 577 769 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (512 ) Income Tax (Expense) Credit (247 ) (179 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (680 ) $ (163 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense (140 ) 1,042 Subtotal – Interest Rate and Foreign Currency (140 ) 1,042 Reclassifications from AOCI, before Income Tax (Expense) Credit (140 ) (1,696 ) Income Tax (Expense) Credit (49 ) (592 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (91 ) (1,104 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (3,847 ) (3,846 ) Amortization of Actuarial (Gains)/Losses 1,733 2,309 Reclassifications from AOCI, before Income Tax (Expense) Credit (2,114 ) (1,537 ) Income Tax (Expense) Credit (740 ) (538 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1,374 ) (999 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,465 ) $ (2,103 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 412 631 Subtotal – Interest Rate and Foreign Currency 412 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 412 631 Income Tax (Expense) Credit 145 221 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 267 410 Pension and OPEB Amortization of Prior Service Cost (Credit) (198 ) (200 ) Amortization of Actuarial (Gains)/Losses 215 264 Reclassifications from AOCI, before Income Tax (Expense) Credit 17 64 Income Tax (Expense) Credit 6 22 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11 42 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 452 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 1,234 1,893 Subtotal – Interest Rate and Foreign Currency 1,234 1,893 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,234 84 Income Tax (Expense) Credit 432 29 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 802 55 Pension and OPEB Amortization of Prior Service Cost (Credit) (596 ) (597 ) Amortization of Actuarial (Gains)/Losses 647 791 Reclassifications from AOCI, before Income Tax (Expense) Credit 51 194 Income Tax (Expense) Credit 18 66 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 33 128 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 835 $ 183 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (4 ) (3 ) Interest Expense (526 ) (524 ) Subtotal – Interest Rate and Foreign Currency (530 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (530 ) (527 ) Income Tax (Expense) Credit (186 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (344 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (10 ) (9 ) Interest Expense (1,574 ) (1,572 ) Subtotal – Interest Rate and Foreign Currency (1,584 ) (1,581 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,584 ) (1,743 ) Income Tax (Expense) Credit (554 ) (609 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,030 ) $ (1,134 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (291 ) (292 ) Subtotal – Interest Rate and Foreign Currency (291 ) (292 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (291 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (189 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (875 ) (876 ) Subtotal – Interest Rate and Foreign Currency (875 ) (876 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (875 ) (964 ) Income Tax (Expense) Credit (306 ) (338 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (569 ) $ (626 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 665 872 Subtotal – Interest Rate and Foreign Currency 665 872 Reclassifications from AOCI, before Income Tax (Expense) Credit 665 872 Income Tax (Expense) Credit 233 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 432 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (468 ) (478 ) Amortization of Actuarial (Gains)/Losses 99 118 Reclassifications from AOCI, before Income Tax (Expense) Credit (369 ) (360 ) Income Tax (Expense) Credit (129 ) (125 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (240 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 192 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 2,409 2,616 Subtotal – Interest Rate and Foreign Currency 2,409 2,616 Reclassifications from AOCI, before Income Tax (Expense) Credit 2,409 2,515 Income Tax (Expense) Credit 843 879 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,566 1,636 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,402 ) (1,433 ) Amortization of Actuarial (Gains)/Losses 296 351 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,106 ) (1,082 ) Income Tax (Expense) Credit (387 ) (378 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (719 ) (704 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 847 $ 932 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Public Service Co Of Oklahoma [Member] | |
Changes in Accumulated Other Comprehensive Income by Component | PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (189 ) (189 ) Net Current Period Other Comprehensive Loss — (189 ) (189 ) Balance in AOCI as of September 30, 2015 $ — $ 4,374 $ 4,374 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of September 30, 2014 $ — $ 5,132 $ 5,132 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 4,943 $ 4,943 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (569 ) (569 ) Net Current Period Other Comprehensive Loss — (569 ) (569 ) Balance in AOCI as of September 30, 2015 $ — $ 4,374 $ 4,374 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2013 $ 57 $ 5,701 $ 5,758 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI (57 ) (569 ) (626 ) Net Current Period Other Comprehensive Loss (57 ) (569 ) (626 ) Balance in AOCI as of September 30, 2014 $ — $ 5,132 $ 5,132 |
Reclassifications from Accumulated Other Comprehensive Income | APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (342 ) 262 Subtotal – Interest Rate and Foreign Currency (342 ) 262 Reclassifications from AOCI, before Income Tax (Expense) Credit (342 ) 262 Income Tax (Expense) Credit (120 ) 92 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (222 ) 170 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,282 ) (1,281 ) Amortization of Actuarial (Gains)/Losses 577 769 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (512 ) Income Tax (Expense) Credit (247 ) (179 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (680 ) $ (163 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense (140 ) 1,042 Subtotal – Interest Rate and Foreign Currency (140 ) 1,042 Reclassifications from AOCI, before Income Tax (Expense) Credit (140 ) (1,696 ) Income Tax (Expense) Credit (49 ) (592 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (91 ) (1,104 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (3,847 ) (3,846 ) Amortization of Actuarial (Gains)/Losses 1,733 2,309 Reclassifications from AOCI, before Income Tax (Expense) Credit (2,114 ) (1,537 ) Income Tax (Expense) Credit (740 ) (538 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1,374 ) (999 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,465 ) $ (2,103 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 412 631 Subtotal – Interest Rate and Foreign Currency 412 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 412 631 Income Tax (Expense) Credit 145 221 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 267 410 Pension and OPEB Amortization of Prior Service Cost (Credit) (198 ) (200 ) Amortization of Actuarial (Gains)/Losses 215 264 Reclassifications from AOCI, before Income Tax (Expense) Credit 17 64 Income Tax (Expense) Credit 6 22 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11 42 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 452 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 1,234 1,893 Subtotal – Interest Rate and Foreign Currency 1,234 1,893 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,234 84 Income Tax (Expense) Credit 432 29 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 802 55 Pension and OPEB Amortization of Prior Service Cost (Credit) (596 ) (597 ) Amortization of Actuarial (Gains)/Losses 647 791 Reclassifications from AOCI, before Income Tax (Expense) Credit 51 194 Income Tax (Expense) Credit 18 66 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 33 128 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 835 $ 183 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (4 ) (3 ) Interest Expense (526 ) (524 ) Subtotal – Interest Rate and Foreign Currency (530 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (530 ) (527 ) Income Tax (Expense) Credit (186 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (344 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (10 ) (9 ) Interest Expense (1,574 ) (1,572 ) Subtotal – Interest Rate and Foreign Currency (1,584 ) (1,581 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,584 ) (1,743 ) Income Tax (Expense) Credit (554 ) (609 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,030 ) $ (1,134 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (291 ) (292 ) Subtotal – Interest Rate and Foreign Currency (291 ) (292 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (291 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (189 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (875 ) (876 ) Subtotal – Interest Rate and Foreign Currency (875 ) (876 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (875 ) (964 ) Income Tax (Expense) Credit (306 ) (338 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (569 ) $ (626 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 665 872 Subtotal – Interest Rate and Foreign Currency 665 872 Reclassifications from AOCI, before Income Tax (Expense) Credit 665 872 Income Tax (Expense) Credit 233 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 432 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (468 ) (478 ) Amortization of Actuarial (Gains)/Losses 99 118 Reclassifications from AOCI, before Income Tax (Expense) Credit (369 ) (360 ) Income Tax (Expense) Credit (129 ) (125 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (240 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 192 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 2,409 2,616 Subtotal – Interest Rate and Foreign Currency 2,409 2,616 Reclassifications from AOCI, before Income Tax (Expense) Credit 2,409 2,515 Income Tax (Expense) Credit 843 879 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,566 1,636 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,402 ) (1,433 ) Amortization of Actuarial (Gains)/Losses 296 351 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,106 ) (1,082 ) Income Tax (Expense) Credit (387 ) (378 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (719 ) (704 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 847 $ 932 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Southwestern Electric Power Co [Member] | |
Changes in Accumulated Other Comprehensive Income by Component | SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 432 (240 ) 192 Net Current Period Other Comprehensive Income (Loss) — 432 (240 ) 192 Balance in AOCI as of September 30, 2015 $ — $ (9,470 ) $ 2,851 $ (6,619 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (235 ) 332 Net Current Period Other Comprehensive Income (Loss) — 567 (235 ) 332 Balance in AOCI as of September 30, 2014 $ — $ (11,602 ) $ 4,090 $ (7,512 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (11,036 ) $ 3,570 $ (7,466 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 1,566 (719 ) 847 Net Current Period Other Comprehensive Income (Loss) — 1,566 (719 ) 847 Balance in AOCI as of September 30, 2015 $ — $ (9,470 ) $ 2,851 $ (6,619 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Nine Months Ended September 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2013 $ 66 $ (13,304 ) $ 4,794 $ (8,444 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI (66 ) 1,702 (704 ) 932 Net Current Period Other Comprehensive Income (Loss) (66 ) 1,702 (704 ) 932 Balance in AOCI as of September 30, 2014 $ — $ (11,602 ) $ 4,090 $ (7,512 ) |
Reclassifications from Accumulated Other Comprehensive Income | APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (342 ) 262 Subtotal – Interest Rate and Foreign Currency (342 ) 262 Reclassifications from AOCI, before Income Tax (Expense) Credit (342 ) 262 Income Tax (Expense) Credit (120 ) 92 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (222 ) 170 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,282 ) (1,281 ) Amortization of Actuarial (Gains)/Losses 577 769 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (512 ) Income Tax (Expense) Credit (247 ) (179 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (680 ) $ (163 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense (140 ) 1,042 Subtotal – Interest Rate and Foreign Currency (140 ) 1,042 Reclassifications from AOCI, before Income Tax (Expense) Credit (140 ) (1,696 ) Income Tax (Expense) Credit (49 ) (592 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (91 ) (1,104 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (3,847 ) (3,846 ) Amortization of Actuarial (Gains)/Losses 1,733 2,309 Reclassifications from AOCI, before Income Tax (Expense) Credit (2,114 ) (1,537 ) Income Tax (Expense) Credit (740 ) (538 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1,374 ) (999 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,465 ) $ (2,103 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 412 631 Subtotal – Interest Rate and Foreign Currency 412 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 412 631 Income Tax (Expense) Credit 145 221 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 267 410 Pension and OPEB Amortization of Prior Service Cost (Credit) (198 ) (200 ) Amortization of Actuarial (Gains)/Losses 215 264 Reclassifications from AOCI, before Income Tax (Expense) Credit 17 64 Income Tax (Expense) Credit 6 22 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11 42 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 452 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 1,234 1,893 Subtotal – Interest Rate and Foreign Currency 1,234 1,893 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,234 84 Income Tax (Expense) Credit 432 29 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 802 55 Pension and OPEB Amortization of Prior Service Cost (Credit) (596 ) (597 ) Amortization of Actuarial (Gains)/Losses 647 791 Reclassifications from AOCI, before Income Tax (Expense) Credit 51 194 Income Tax (Expense) Credit 18 66 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 33 128 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 835 $ 183 OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (4 ) (3 ) Interest Expense (526 ) (524 ) Subtotal – Interest Rate and Foreign Currency (530 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (530 ) (527 ) Income Tax (Expense) Credit (186 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (344 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (10 ) (9 ) Interest Expense (1,574 ) (1,572 ) Subtotal – Interest Rate and Foreign Currency (1,584 ) (1,581 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,584 ) (1,743 ) Income Tax (Expense) Credit (554 ) (609 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (1,030 ) $ (1,134 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense (291 ) (292 ) Subtotal – Interest Rate and Foreign Currency (291 ) (292 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (291 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (189 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (875 ) (876 ) Subtotal – Interest Rate and Foreign Currency (875 ) (876 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (875 ) (964 ) Income Tax (Expense) Credit (306 ) (338 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (569 ) $ (626 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Interest Expense 665 872 Subtotal – Interest Rate and Foreign Currency 665 872 Reclassifications from AOCI, before Income Tax (Expense) Credit 665 872 Income Tax (Expense) Credit 233 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 432 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (468 ) (478 ) Amortization of Actuarial (Gains)/Losses 99 118 Reclassifications from AOCI, before Income Tax (Expense) Credit (369 ) (360 ) Income Tax (Expense) Credit (129 ) (125 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (240 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 192 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Nine Months Ended September 30, 2015 and 2014 Amount of (Gain) Loss Nine Months Ended September 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 2,409 2,616 Subtotal – Interest Rate and Foreign Currency 2,409 2,616 Reclassifications from AOCI, before Income Tax (Expense) Credit 2,409 2,515 Income Tax (Expense) Credit 843 879 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,566 1,636 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,402 ) (1,433 ) Amortization of Actuarial (Gains)/Losses 296 351 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,106 ) (1,082 ) Income Tax (Expense) Credit (387 ) (378 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (719 ) (704 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 847 $ 932 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Rate Matters (Tables)
Rate Matters (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Regulatory Assets Pending Final Regulatory Approval | Regulatory Assets Pending Final Regulatory Approval September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Storm Related Costs $ 24 $ 20 Material and Supplies Related to Retired Plants 20 — West Virginia Vegetation Management Program — 20 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 59 — Virginia Peak Demand Reduction/Energy Efficiency 12 9 Ormet Special Rate Recovery Mechanism 10 10 Storm Related Costs 7 100 Carbon Capture and Storage Product Validation Facility — 13 IGCC Pre-Construction Costs — 11 Other Regulatory Assets Pending Final Regulatory Approval 27 43 Total Regulatory Assets Pending Final Regulatory Approval $ 159 $ 226 |
Appalachian Power Co [Member] | |
Regulatory Assets Pending Final Regulatory Approval | Regulatory Assets Pending Final Regulatory Approval APCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 8,592 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 32,128 — Peak Demand Reduction/Energy Efficiency – Virginia 11,650 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Deferred Permit Fees Related to Retired Plants – West Virginia 617 — Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory – West Virginia — 3,421 Expanded Net Energy Charge – Construction Surcharge – West Virginia — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval — 168 Total Regulatory Assets Pending Final Regulatory Approval $ 54,937 $ 125,748 I&M September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,652 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,955 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 3,445 1,222 Rockport Dry Sorbent Injection System 1,865 148 Storm Related Costs – Indiana — 1,074 Other Regulatory Assets Pending Final Regulatory Approval 11 712 Total Regulatory Assets Pending Final Regulatory Approval $ 56,904 $ 13,649 OPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Total Regulatory Assets Pending Final Regulatory Approval $ 10,483 $ 10,483 PSO September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project $ 3,031 $ 2,287 Asset Retirement Obligation 1,516 1,144 Rate Case Expenses — 8,126 Other Regulatory Assets Pending Final Regulatory Approval 695 558 Total Regulatory Assets Pending Final Regulatory Approval $ 5,242 $ 12,115 |
Indiana Michigan Power Co [Member] | |
Regulatory Assets Pending Final Regulatory Approval | Regulatory Assets Pending Final Regulatory Approval APCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 8,592 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 32,128 — Peak Demand Reduction/Energy Efficiency – Virginia 11,650 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Deferred Permit Fees Related to Retired Plants – West Virginia 617 — Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory – West Virginia — 3,421 Expanded Net Energy Charge – Construction Surcharge – West Virginia — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval — 168 Total Regulatory Assets Pending Final Regulatory Approval $ 54,937 $ 125,748 I&M September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,652 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,955 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 3,445 1,222 Rockport Dry Sorbent Injection System 1,865 148 Storm Related Costs – Indiana — 1,074 Other Regulatory Assets Pending Final Regulatory Approval 11 712 Total Regulatory Assets Pending Final Regulatory Approval $ 56,904 $ 13,649 OPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Total Regulatory Assets Pending Final Regulatory Approval $ 10,483 $ 10,483 PSO September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project $ 3,031 $ 2,287 Asset Retirement Obligation 1,516 1,144 Rate Case Expenses — 8,126 Other Regulatory Assets Pending Final Regulatory Approval 695 558 Total Regulatory Assets Pending Final Regulatory Approval $ 5,242 $ 12,115 |
Ohio Power Co [Member] | |
Regulatory Assets Pending Final Regulatory Approval | Regulatory Assets Pending Final Regulatory Approval APCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 8,592 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 32,128 — Peak Demand Reduction/Energy Efficiency – Virginia 11,650 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Deferred Permit Fees Related to Retired Plants – West Virginia 617 — Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory – West Virginia — 3,421 Expanded Net Energy Charge – Construction Surcharge – West Virginia — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval — 168 Total Regulatory Assets Pending Final Regulatory Approval $ 54,937 $ 125,748 I&M September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,652 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,955 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 3,445 1,222 Rockport Dry Sorbent Injection System 1,865 148 Storm Related Costs – Indiana — 1,074 Other Regulatory Assets Pending Final Regulatory Approval 11 712 Total Regulatory Assets Pending Final Regulatory Approval $ 56,904 $ 13,649 OPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Total Regulatory Assets Pending Final Regulatory Approval $ 10,483 $ 10,483 PSO September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project $ 3,031 $ 2,287 Asset Retirement Obligation 1,516 1,144 Rate Case Expenses — 8,126 Other Regulatory Assets Pending Final Regulatory Approval 695 558 Total Regulatory Assets Pending Final Regulatory Approval $ 5,242 $ 12,115 |
Public Service Co Of Oklahoma [Member] | |
Regulatory Assets Pending Final Regulatory Approval | Regulatory Assets Pending Final Regulatory Approval APCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 8,592 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 32,128 — Peak Demand Reduction/Energy Efficiency – Virginia 11,650 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Deferred Permit Fees Related to Retired Plants – West Virginia 617 — Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory – West Virginia — 3,421 Expanded Net Energy Charge – Construction Surcharge – West Virginia — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval — 168 Total Regulatory Assets Pending Final Regulatory Approval $ 54,937 $ 125,748 I&M September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,652 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,955 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 3,445 1,222 Rockport Dry Sorbent Injection System 1,865 148 Storm Related Costs – Indiana — 1,074 Other Regulatory Assets Pending Final Regulatory Approval 11 712 Total Regulatory Assets Pending Final Regulatory Approval $ 56,904 $ 13,649 OPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Total Regulatory Assets Pending Final Regulatory Approval $ 10,483 $ 10,483 PSO September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project $ 3,031 $ 2,287 Asset Retirement Obligation 1,516 1,144 Rate Case Expenses — 8,126 Other Regulatory Assets Pending Final Regulatory Approval 695 558 Total Regulatory Assets Pending Final Regulatory Approval $ 5,242 $ 12,115 |
Southwestern Electric Power Co [Member] | |
Regulatory Assets Pending Final Regulatory Approval | Regulatory Assets Pending Final Regulatory Approval APCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 8,592 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 32,128 — Peak Demand Reduction/Energy Efficiency – Virginia 11,650 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Deferred Permit Fees Related to Retired Plants – West Virginia 617 — Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory – West Virginia — 3,421 Expanded Net Energy Charge – Construction Surcharge – West Virginia — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval — 168 Total Regulatory Assets Pending Final Regulatory Approval $ 54,937 $ 125,748 I&M September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,652 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,955 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 3,445 1,222 Rockport Dry Sorbent Injection System 1,865 148 Storm Related Costs – Indiana — 1,074 Other Regulatory Assets Pending Final Regulatory Approval 11 712 Total Regulatory Assets Pending Final Regulatory Approval $ 56,904 $ 13,649 OPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Total Regulatory Assets Pending Final Regulatory Approval $ 10,483 $ 10,483 PSO September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo September 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project $ 3,031 $ 2,287 Asset Retirement Obligation 1,516 1,144 Rate Case Expenses — 8,126 Other Regulatory Assets Pending Final Regulatory Approval 695 558 Total Regulatory Assets Pending Final Regulatory Approval $ 5,242 $ 12,115 |
Commitments, Guarantees and C34
Commitments, Guarantees and Contingencies (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Appalachian Power Co [Member] | |
Maximum Future Payments of Letters of Credit | Company Amount Maturity (in thousands) I&M $ 35 March 2016 |
Maximum Future Payments for Letters of Credit Uncommitted Facilities | Company Amount Maturity (in thousands) OPCo $ 4,200 September 2016 |
Pollution Control Bonds Supported by Bilateral Letters of Credit | Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 |
Maximum Potential Loss on Master Lease Agreements | Company Maximum Potential Loss (in thousands) APCo $ 5,396 I&M 3,448 OPCo 6,075 PSO 2,785 SWEPCo 3,086 |
Indiana Michigan Power Co [Member] | |
Maximum Future Payments of Letters of Credit | Company Amount Maturity (in thousands) I&M $ 35 March 2016 |
Maximum Future Payments for Letters of Credit Uncommitted Facilities | Company Amount Maturity (in thousands) OPCo $ 4,200 September 2016 |
Pollution Control Bonds Supported by Bilateral Letters of Credit | Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 |
Maximum Potential Loss on Master Lease Agreements | Company Maximum Potential Loss (in thousands) APCo $ 5,396 I&M 3,448 OPCo 6,075 PSO 2,785 SWEPCo 3,086 |
Ohio Power Co [Member] | |
Maximum Future Payments of Letters of Credit | Company Amount Maturity (in thousands) I&M $ 35 March 2016 |
Maximum Future Payments for Letters of Credit Uncommitted Facilities | Company Amount Maturity (in thousands) OPCo $ 4,200 September 2016 |
Pollution Control Bonds Supported by Bilateral Letters of Credit | Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 |
Maximum Potential Loss on Master Lease Agreements | Company Maximum Potential Loss (in thousands) APCo $ 5,396 I&M 3,448 OPCo 6,075 PSO 2,785 SWEPCo 3,086 |
Public Service Co Of Oklahoma [Member] | |
Maximum Future Payments of Letters of Credit | Company Amount Maturity (in thousands) I&M $ 35 March 2016 |
Maximum Future Payments for Letters of Credit Uncommitted Facilities | Company Amount Maturity (in thousands) OPCo $ 4,200 September 2016 |
Pollution Control Bonds Supported by Bilateral Letters of Credit | Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 |
Maximum Potential Loss on Master Lease Agreements | Company Maximum Potential Loss (in thousands) APCo $ 5,396 I&M 3,448 OPCo 6,075 PSO 2,785 SWEPCo 3,086 |
Southwestern Electric Power Co [Member] | |
Maximum Future Payments of Letters of Credit | Company Amount Maturity (in thousands) I&M $ 35 March 2016 |
Maximum Future Payments for Letters of Credit Uncommitted Facilities | Company Amount Maturity (in thousands) OPCo $ 4,200 September 2016 |
Pollution Control Bonds Supported by Bilateral Letters of Credit | Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 |
Maximum Potential Loss on Master Lease Agreements | Company Maximum Potential Loss (in thousands) APCo $ 5,396 I&M 3,448 OPCo 6,075 PSO 2,785 SWEPCo 3,086 |
Dispositions, Assets and Liabil
Dispositions, Assets and Liabilities Held for Sale and Discontinued Operations (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Assets and Liabilities Held for Sale and Results of Discontinued Operations | Three Months Ended Nine Months Ended 2015 2014 2015 2014 (in millions) Other Revenues $ 129 $ 141 $ 372 $ 435 Other Operation Expense 96 102 273 342 Maintenance Expense 4 8 20 24 Depreciation and Amortization Expense 9 8 27 23 Other Expense 8 7 24 22 Total Expenses 117 125 344 411 Pretax Income of Discontinued Operations 12 16 28 24 Income Tax Expense 4 5 10 8 Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income $ 8 $ 11 $ 18 $ 16 September 30, 2015 December 31, 2014 Assets: (in millions) Accounts Receivable $ 55 $ 91 Property, Plant and Equipment – Net 506 482 Other Classes of Assets That Are Not Major 47 52 Total Assets Classified as Held for Sale on the Condensed Consolidated Balance Sheets $ 608 $ 625 Liabilities: Long-term Debt $ 81 $ 83 Obligations Under Capital Leases 228 189 Other Classes of Liabilities That Are Not Major 165 163 Total Liabilities Classified as Held for Sale on the Condensed Consolidated Balance Sheets $ 474 $ 435 |
Benefit Plans (Tables)
Benefit Plans (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Components of Net Periodic Benefit Cost | Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in millions) Service Cost $ 23 $ 18 $ 3 $ 4 Interest Cost 51 55 15 16 Expected Return on Plan Assets (69 ) (65 ) (28 ) (28 ) Amortization of Prior Service Cost (Credit) 1 1 (18 ) (18 ) Amortization of Net Actuarial Loss 27 31 5 6 Net Periodic Benefit Cost (Credit) $ 33 $ 40 $ (23 ) $ (20 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in millions) Service Cost $ 70 $ 54 $ 9 $ 11 Interest Cost 154 166 43 50 Expected Return on Plan Assets (206 ) (196 ) (83 ) (84 ) Amortization of Prior Service Cost (Credit) 2 2 (52 ) (52 ) Amortization of Net Actuarial Loss 80 93 14 17 Net Periodic Benefit Cost (Credit) $ 100 $ 119 $ (69 ) $ (58 ) |
Appalachian Power Co [Member] | |
Components of Net Periodic Benefit Cost | APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,175 $ 1,759 $ 286 $ 362 Interest Cost 6,679 7,406 2,584 3,197 Expected Return on Plan Assets (8,745 ) (8,482 ) (4,529 ) (4,634 ) Amortization of Prior Service Cost (Credit) 45 49 (2,513 ) (2,512 ) Amortization of Net Actuarial Loss 3,474 4,149 900 1,145 Net Periodic Benefit Cost (Credit) $ 3,628 $ 4,881 $ (3,272 ) $ (2,442 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,525 $ 5,277 $ 857 $ 1,086 Interest Cost 20,037 22,218 7,753 9,591 Expected Return on Plan Assets (26,236 ) (25,445 ) (13,587 ) (13,900 ) Amortization of Prior Service Cost (Credit) 135 148 (7,538 ) (7,537 ) Amortization of Net Actuarial Loss 10,421 12,445 2,699 3,436 Net Periodic Benefit Cost (Credit) $ 10,882 $ 14,643 $ (9,816 ) $ (7,324 ) |
Indiana Michigan Power Co [Member] | |
Components of Net Periodic Benefit Cost | I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,217 $ 2,517 $ 406 $ 486 Interest Cost 6,114 6,573 1,592 1,909 Expected Return on Plan Assets (8,115 ) (7,749 ) (3,304 ) (3,363 ) Amortization of Prior Service Cost (Credit) 45 49 (2,355 ) (2,355 ) Amortization of Net Actuarial Loss 3,145 3,647 506 592 Net Periodic Benefit Cost (Credit) $ 4,406 $ 5,037 $ (3,155 ) $ (2,731 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 9,651 $ 7,551 $ 1,219 $ 1,460 Interest Cost 18,344 19,720 4,776 5,728 Expected Return on Plan Assets (24,347 ) (23,245 ) (9,912 ) (10,090 ) Amortization of Prior Service Cost (Credit) 136 146 (7,066 ) (7,066 ) Amortization of Net Actuarial Loss 9,434 10,939 1,519 1,776 Net Periodic Benefit Cost (Credit) $ 13,218 $ 15,111 $ (9,464 ) $ (8,192 ) |
Ohio Power Co [Member] | |
Components of Net Periodic Benefit Cost | OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,671 $ 1,285 $ 216 $ 256 Interest Cost 5,071 5,527 1,615 1,900 Expected Return on Plan Assets (6,878 ) (6,607 ) (3,376 ) (3,379 ) Amortization of Prior Service Cost (Credit) 35 40 (1,731 ) (1,731 ) Amortization of Net Actuarial Loss 2,644 3,105 517 595 Net Periodic Benefit Cost (Credit) $ 2,543 $ 3,350 $ (2,759 ) $ (2,359 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 5,015 $ 3,855 $ 647 $ 769 Interest Cost 15,211 16,579 4,845 5,701 Expected Return on Plan Assets (20,634 ) (19,820 ) (10,130 ) (10,139 ) Amortization of Prior Service Cost (Credit) 105 118 (5,192 ) (5,192 ) Amortization of Net Actuarial Loss 7,932 9,316 1,552 1,785 Net Periodic Benefit Cost (Credit) $ 7,629 $ 10,048 $ (8,278 ) $ (7,076 ) |
Public Service Co Of Oklahoma [Member] | |
Components of Net Periodic Benefit Cost | PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,598 $ 1,301 $ 170 $ 209 Interest Cost 2,731 3,015 759 893 Expected Return on Plan Assets (3,786 ) (3,651 ) (1,578 ) (1,575 ) Amortization of Prior Service Cost (Credit) 63 74 (1,072 ) (1,072 ) Amortization of Net Actuarial Loss 1,418 1,689 242 278 Net Periodic Benefit Cost (Credit) $ 2,024 $ 2,428 $ (1,479 ) $ (1,267 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,796 $ 3,905 $ 509 $ 629 Interest Cost 8,194 9,043 2,277 2,680 Expected Return on Plan Assets (11,358 ) (10,953 ) (4,732 ) (4,725 ) Amortization of Prior Service Cost (Credit) 189 222 (3,217 ) (3,217 ) Amortization of Net Actuarial Loss 4,252 5,065 725 832 Net Periodic Benefit Cost (Credit) $ 6,073 $ 7,282 $ (4,438 ) $ (3,801 ) |
Southwestern Electric Power Co [Member] | |
Components of Net Periodic Benefit Cost | SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,081 $ 1,655 $ 211 $ 253 Interest Cost 2,932 3,163 837 998 Expected Return on Plan Assets (4,008 ) (3,857 ) (1,735 ) (1,754 ) Amortization of Prior Service Cost (Credit) 78 87 (1,289 ) (1,289 ) Amortization of Net Actuarial Loss 1,506 1,762 266 309 Net Periodic Benefit Cost (Credit) $ 2,589 $ 2,810 $ (1,710 ) $ (1,483 ) Pension Plans Other Postretirement Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,244 $ 4,964 $ 632 $ 759 Interest Cost 8,796 9,488 2,512 2,994 Expected Return on Plan Assets (12,024 ) (11,571 ) (5,206 ) (5,262 ) Amortization of Prior Service Cost (Credit) 232 262 (3,867 ) (3,867 ) Amortization of Net Actuarial Loss 4,520 5,285 798 926 Net Periodic Benefit Cost (Credit) $ 7,768 $ 8,428 $ (5,131 ) $ (4,450 ) |
Business Segments (Tables)
Business Segments (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Segment Reporting [Abstract] | |
Reportable Segment Information | Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,436 $ 1,164 $ 27 $ 802 $ — $ 3 $ — (c) $ 4,432 Other Operating Segments 35 25 61 33 — 21 (175 ) — Total Revenues $ 2,471 $ 1,189 $ 88 $ 835 $ — $ 24 $ (175 ) $ 4,432 Income (Loss) from Continuing Operations $ 275 $ 113 $ 46 $ 91 $ (4 ) $ (9 ) $ — $ 512 Income from Discontinued Operations, Net of Tax — — — — 8 — — 8 Net Income (Loss) $ 275 $ 113 $ 46 $ 91 $ 4 $ (9 ) $ — $ 520 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,432 (b) $ 1,163 $ 21 $ 538 (b) $ — $ 7 $ — (c) $ 4,161 Other Operating Segments 18 (b) 68 34 363 (b) — 19 (502 ) — Total Revenues $ 2,450 $ 1,231 $ 55 $ 901 $ — $ 26 $ (502 ) $ 4,161 Income from Continuing Operations $ 220 $ 92 $ 43 $ 117 $ — $ 11 $ — $ 483 Income from Discontinued Operations, Net of Tax — — — — 11 — — 11 Net Income $ 220 $ 92 $ 43 $ 117 $ 11 $ 11 $ — $ 494 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended Revenues from: External Customers $ 7,082 $ 3,378 $ 74 $ 2,289 $ — $ 16 $ — (c) $ 12,839 Other Operating Segments 77 142 171 517 — 58 (965 ) — Total Revenues $ 7,159 $ 3,520 $ 245 $ 2,806 $ — $ 74 $ (965 ) $ 12,839 Income (Loss) from Continuing Operations $ 783 $ 288 $ 148 $ 360 $ (2 ) $ (13 ) $ — $ 1,564 Income from Discontinued Operations, Net of Tax — — — — 18 — — 18 Net Income (Loss) $ 783 $ 288 $ 148 $ 360 $ 16 $ (13 ) $ — $ 1,582 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Nine Months Ended Revenues from: External Customers $ 7,217 (b) $ 3,388 $ 54 $ 1,932 (b) $ — $ 19 $ (51 ) (c) $ 12,559 Other Operating Segments 71 (b) 192 86 1,133 (b) — 55 (1,537 ) — Total Revenues $ 7,288 $ 3,580 $ 140 $ 3,065 $ — $ 74 $ (1,588 ) $ 12,559 Income from Continuing Operations $ 654 $ 279 $ 114 $ 378 $ 1 $ 4 $ — $ 1,430 Income from Discontinued Operations, Net of Tax — — — — 16 — — 16 Net Income $ 654 $ 279 $ 114 $ 378 $ 17 $ 4 $ — $ 1,446 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) September 30, 2015 Total Property, Plant and Equipment $ 39,981 $ 13,707 $ 3,594 $ 7,474 $ — $ 349 $ (279 ) (d) $ 64,826 Accumulated Depreciation and Amortization 12,483 3,603 43 3,390 — 178 (109 ) (d) 19,588 Total Property, Plant and Equipment - Net $ 27,498 $ 10,104 $ 3,551 $ 4,084 $ — $ 171 $ (170 ) (d) $ 45,238 Assets Held for Sale $ — $ — $ — $ — $ 608 $ — $ — $ 608 Total Assets 35,272 14,441 4,362 5,531 772 (f) 21,810 (21,089 ) (d) (e) 61,099 Long-term Debt Due Within One Year: Affiliated $ — $ — $ — $ — $ — $ — $ — $ — Nonaffiliated 949 724 — 151 — 2 — 1,826 Long-term Debt: Affiliated 20 — — 32 — — (52 ) — Nonaffiliated 9,900 4,888 1,323 641 — 848 — 17,600 Total Long-term Debt $ 10,869 $ 5,612 $ 1,323 $ 824 $ — $ 850 $ (52 ) $ 19,426 Liabilities Held for Sale $ — $ — $ — $ — $ 474 $ — $ — $ 474 (g) Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2014 Total Property, Plant and Equipment $ 39,402 $ 13,024 $ 2,714 $ 8,394 $ — $ 343 $ (271 ) (d) $ 63,606 Accumulated Depreciation and Amortization 12,773 3,481 25 3,603 — 188 (99 ) (d) 19,971 Total Property, Plant and Equipment - Net $ 26,629 $ 9,543 $ 2,689 $ 4,791 $ — $ 155 $ (172 ) (d) $ 43,635 Assets Held for Sale $ — $ — $ — $ — $ 625 $ — $ — $ 625 Total Assets 33,750 14,495 3,575 6,329 749 (f) 21,081 (20,346 ) (d) (e) 59,633 Long-term Debt Due Within One Year: Affiliated $ 111 $ — $ — $ 86 $ — $ — $ (197 ) $ — Nonaffiliated 1,352 405 — 740 — 3 — 2,500 Long-term Debt: Affiliated 20 — — 32 — — (52 ) — Nonaffiliated 8,634 5,256 1,153 217 — 841 — 16,101 Total Long-term Debt $ 10,117 $ 5,661 $ 1,153 $ 1,075 $ — $ 844 $ (249 ) $ 18,601 Liabilities Held for Sale $ — $ — $ — $ — $ 435 $ — $ — $ 435 (g) (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes the impact of corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies. (f) Amounts include intercompany advances to affiliates and intercompany accounts receivable that will be settled prior to or upon the close of the sale of AEPRO. (g) Amounts include debt related to AEPRO. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. |
Derivatives and Hedging (Tables
Derivatives and Hedging (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments Volume September 30, December 31, Unit of Measure Primary Risk Exposure (in millions) Commodity: Power 371 334 MWhs Coal 4 3 Tons Natural Gas 46 106 MMBtus Heating Oil and Gasoline 9 6 Gallons Interest Rate $ 114 $ 152 USD Interest Rate and Foreign Currency $ 560 $ 815 USD |
Fair Value of Derivative Instruments | Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 311 $ 9 $ 2 $ 322 $ (179 ) $ 143 Long-term Risk Management Assets 443 3 — 446 (93 ) 353 Total Assets 754 12 2 768 (272 ) 496 Current Risk Management Liabilities 267 7 1 275 (200 ) 75 Long-term Risk Management Liabilities 293 22 1 316 (115 ) 201 Total Liabilities 560 29 2 591 (315 ) 276 Total MTM Derivative Contract Net Assets (Liabilities) $ 194 $ (17 ) $ — $ 177 $ 43 $ 220 Fair Value of Derivative Instruments December 31, 2014 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (in millions) Current Risk Management Assets $ 392 $ 30 $ 3 $ 425 $ (247 ) $ 178 Long-term Risk Management Assets 367 3 — 370 (76 ) 294 Total Assets 759 33 3 795 (323 ) 472 Current Risk Management Liabilities 329 23 1 353 (261 ) 92 Long-term Risk Management Liabilities 208 8 9 225 (94 ) 131 Total Liabilities 537 31 10 578 (355 ) 223 Total MTM Derivative Contract Net Assets (Liabilities) $ 222 $ 2 $ (7 ) $ 217 $ 32 $ 249 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
Amount of Gain (Loss) Recognized on Risk Management Contracts | Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three and Nine Months Ended September 30, 2015 and 2014 Three Months Ended Nine Months Ended September 30, September 30, Location of Gain (Loss) 2015 2014 2015 2014 (in millions) Vertically Integrated Utilities Revenues $ — $ 7 $ 7 $ 29 Transmission and Distribution Utilities Revenues (1 ) — (1 ) — Generation & Marketing Revenues 1 21 60 69 Other Operation Expense — — (1 ) — Maintenance Expense (1 ) — (2 ) — Purchased Electricity for Resale 1 — 4 — Regulatory Assets (a) — (6 ) — (6 ) Regulatory Liabilities (a) (20 ) (7 ) 33 111 Total Gain (Loss) on Risk Management Contracts $ (20 ) $ 15 $ 100 $ 203 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Gain (Loss) on Hedging Instruments | Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 4 $ (2 ) $ 7 $ 2 Gain (Loss) on Fair Value Portion of Long-term Debt (4 ) 2 (7 ) (2 ) |
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Condensed Balance Sheet September 30, 2015 Commodity Interest Rate Currency Total (in millions) Hedging Assets (a) $ 7 $ — $ 7 Hedging Liabilities (a) 24 1 25 AOCI Loss Net of Tax (11 ) (18 ) (29 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 1 (1 ) — Impact of Cash Flow Hedges on the Condensed Balance Sheet December 31, 2014 Commodity Interest Rate Total (in millions) Hedging Assets (a) $ 16 $ — $ 16 Hedging Liabilities (a) 14 1 15 AOCI Gain (Loss) Net of Tax 1 (19 ) (18 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4 (2 ) 2 (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. |
Collateral Required Under Various Triggering Events | September 30, December 31, 2015 2014 (in millions) Fair Value of Contracts with Credit Downgrade Triggers $ — $ — Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement — — Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs 35 36 Amount of Collateral Attributable to Other Contracts (a) 299 281 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contracts. |
Liabilities Subject to Cross Default Provisions | September 30, December 31, (in millions) Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements $ 307 $ 235 Amount of Cash Collateral Posted 10 9 Additional Settlement Liability if Cross Default Provision is Triggered 251 178 |
Appalachian Power Co [Member] | |
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments September 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 62,306 30,345 13,470 17,580 21,736 Coal Tons 116 1,468 — — 2,125 Natural Gas MMBtus 256 174 — — — Heating Oil and Gasoline Gallons 1,763 836 1,858 1,019 1,166 Interest Rate USD $ 2,645 $ 1,794 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — |
Cash Collateral Netting | September 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 1,688 $ 68 $ 98 I&M — 333 163 47 OPCo — 500 — 102 PSO — 280 — 54 SWEPCo — 319 — 62 |
Fair Value of Derivative Instruments | APCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated and Affiliated $ 34,278 $ — $ — $ 34,278 $ (6,928 ) $ 27,350 Long-term Risk Management Assets - Nonaffiliated 2,485 — — 2,485 (450 ) 2,035 Total Assets 36,763 — — 36,763 (7,378 ) 29,385 Current Risk Management Liabilities - Nonaffiliated 15,345 — — 15,345 (8,443 ) 6,902 Long-term Risk Management Liabilities - Nonaffiliated 1,596 — — 1,596 (623 ) 973 Total Liabilities 16,941 — — 16,941 (9,066 ) 7,875 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,822 $ — $ — $ 19,822 $ 1,688 $ 21,510 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated $ 32,903 $ — $ — $ 32,903 $ (9,111 ) $ 23,792 Long-term Risk Management Assets - Nonaffiliated 5,159 — — 5,159 (268 ) 4,891 Total Assets 38,062 — — 38,062 (9,379 ) 28,683 Current Risk Management Liabilities - Non Affiliated 20,161 — — 20,161 (9,144 ) 11,017 Long-term Risk Management Liabilities - Nonaffiliated 2,322 — — 2,322 (265 ) 2,057 Total Liabilities 22,483 — — 22,483 (9,409 ) 13,074 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,579 $ — $ — $ 15,579 $ 30 $ 15,609 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
Amount of Gain (Loss) Recognized on Risk Management Contracts | Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ (369 ) $ 350 $ (917 ) $ (9 ) $ (7 ) Sales to AEP Affiliates 1,156 3,336 — — — Other Operation Expense (88 ) (63 ) (128 ) (109 ) (127 ) Maintenance Expense (164 ) (86 ) (140 ) (88 ) (88 ) Purchased Electricity for Resale 831 15 30 — — Regulatory Assets (a) 861 (981 ) — (190 ) 188 Regulatory Liabilities (a) 3,197 (1,718 ) (22,281 ) (498 ) 1,137 Total Gain (Loss) on Risk Management Contracts $ 5,424 $ 853 $ (23,436 ) $ (894 ) $ 1,103 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,231 $ 2,988 $ 41 $ 45 $ 74 Sales to AEP Affiliates — (196 ) — 196 — Regulatory Assets (a) (2,571 ) (471 ) (852 ) (109 ) (284 ) Regulatory Liabilities (a) (3,606 ) (176 ) (1,555 ) 120 (180 ) Total Gain (Loss) on Risk Management Contracts $ (4,946 ) $ 2,145 $ (2,366 ) $ 252 $ (390 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 790 $ 3,591 $ (882 ) $ 16 $ 19 Sales to AEP Affiliates 1,511 4,341 — — — Other Operation Expense (287 ) (221 ) (389 ) (307 ) (373 ) Maintenance Expense (503 ) (221 ) (396 ) (248 ) (265 ) Purchased Electricity for Resale 1,571 347 30 — — Regulatory Assets (a) 2,136 (1,213 ) — 615 (1,234 ) Regulatory Liabilities (a) 31,797 4,121 (24,880 ) 5,076 14,446 Total Gain (Loss) on Risk Management Contracts $ 37,015 $ 10,745 $ (26,517 ) $ 5,152 $ 12,593 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 7,262 $ 10,467 $ 97 $ 172 $ 18 Sales to AEP Affiliates — (717 ) — 717 — Regulatory Assets (a) (2,567 ) (471 ) (215 ) (119 ) (285 ) Regulatory Liabilities (a) 42,444 26,934 39,311 (69 ) 119 Total Gain (Loss) on Risk Management Contracts $ 47,139 $ 36,213 $ 39,193 $ 701 $ (148 ) (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets September 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,805 I&M — — — — — (13,604 ) OPCo — — — — — 4,572 PSO — — — — — 4,374 SWEPCo — — — — — (9,470 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 734 0 I&M — (1,277 ) 0 OPCo — 1,282 0 PSO — 771 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. |
Collateral Required Under Various Triggering Events | September 30, 2015 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 2,913 $ 97 I&M — — 1,976 66 OPCo — — — — PSO — — 2,692 3,247 SWEPCo — — 3,328 58 December 31, 2014 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 6,339 $ 74 I&M — — 4,299 47 OPCo — — — — PSO — — 693 4,111 SWEPCo — — 877 166 |
Liabilities Subject to Cross Default Provisions | September 30, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 5,310 $ — $ 5,288 I&M 3,601 — 3,586 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 9,043 $ — $ 9,012 I&M 6,134 — 6,113 OPCo — — — PSO — — — SWEPCo — — — |
Indiana Michigan Power Co [Member] | |
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments September 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 62,306 30,345 13,470 17,580 21,736 Coal Tons 116 1,468 — — 2,125 Natural Gas MMBtus 256 174 — — — Heating Oil and Gasoline Gallons 1,763 836 1,858 1,019 1,166 Interest Rate USD $ 2,645 $ 1,794 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — |
Cash Collateral Netting | September 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 1,688 $ 68 $ 98 I&M — 333 163 47 OPCo — 500 — 102 PSO — 280 — 54 SWEPCo — 319 — 62 |
Fair Value of Derivative Instruments | I&M Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated and Affiliated $ 16,675 $ — $ — $ 16,675 $ (6,048 ) $ 10,627 Long-term Risk Management Assets - Nonaffiliated 1,619 — — 1,619 (281 ) 1,338 Total Assets 18,294 — — 18,294 (6,329 ) 11,965 Current Risk Management Liabilities - Nonaffiliated 10,901 — — 10,901 (6,286 ) 4,615 Long-term Risk Management Liabilities - Nonaffiliated 1,624 — — 1,624 (376 ) 1,248 Total Liabilities 12,525 — — 12,525 (6,662 ) 5,863 Total MTM Derivative Contract Net Assets (Liabilities) $ 5,769 $ — $ — $ 5,769 $ 333 $ 6,102 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets - Nonaffiliated $ 28,545 $ — $ — $ 28,545 $ (6,217 ) $ 22,328 Long-term Risk Management Assets - Nonaffiliated 3,499 — — 3,499 (182 ) 3,317 Total Assets 32,044 — — 32,044 (6,399 ) 25,645 Current Risk Management Liabilities - Nonaffiliated 11,326 — — 11,326 (6,103 ) 5,223 Long-term Risk Management Liabilities - Nonaffiliated 1,575 — — 1,575 (180 ) 1,395 Total Liabilities 12,901 — — 12,901 (6,283 ) 6,618 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,143 $ — $ — $ 19,143 $ (116 ) $ 19,027 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
Amount of Gain (Loss) Recognized on Risk Management Contracts | Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ (369 ) $ 350 $ (917 ) $ (9 ) $ (7 ) Sales to AEP Affiliates 1,156 3,336 — — — Other Operation Expense (88 ) (63 ) (128 ) (109 ) (127 ) Maintenance Expense (164 ) (86 ) (140 ) (88 ) (88 ) Purchased Electricity for Resale 831 15 30 — — Regulatory Assets (a) 861 (981 ) — (190 ) 188 Regulatory Liabilities (a) 3,197 (1,718 ) (22,281 ) (498 ) 1,137 Total Gain (Loss) on Risk Management Contracts $ 5,424 $ 853 $ (23,436 ) $ (894 ) $ 1,103 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,231 $ 2,988 $ 41 $ 45 $ 74 Sales to AEP Affiliates — (196 ) — 196 — Regulatory Assets (a) (2,571 ) (471 ) (852 ) (109 ) (284 ) Regulatory Liabilities (a) (3,606 ) (176 ) (1,555 ) 120 (180 ) Total Gain (Loss) on Risk Management Contracts $ (4,946 ) $ 2,145 $ (2,366 ) $ 252 $ (390 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 790 $ 3,591 $ (882 ) $ 16 $ 19 Sales to AEP Affiliates 1,511 4,341 — — — Other Operation Expense (287 ) (221 ) (389 ) (307 ) (373 ) Maintenance Expense (503 ) (221 ) (396 ) (248 ) (265 ) Purchased Electricity for Resale 1,571 347 30 — — Regulatory Assets (a) 2,136 (1,213 ) — 615 (1,234 ) Regulatory Liabilities (a) 31,797 4,121 (24,880 ) 5,076 14,446 Total Gain (Loss) on Risk Management Contracts $ 37,015 $ 10,745 $ (26,517 ) $ 5,152 $ 12,593 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 7,262 $ 10,467 $ 97 $ 172 $ 18 Sales to AEP Affiliates — (717 ) — 717 — Regulatory Assets (a) (2,567 ) (471 ) (215 ) (119 ) (285 ) Regulatory Liabilities (a) 42,444 26,934 39,311 (69 ) 119 Total Gain (Loss) on Risk Management Contracts $ 47,139 $ 36,213 $ 39,193 $ 701 $ (148 ) (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets September 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,805 I&M — — — — — (13,604 ) OPCo — — — — — 4,572 PSO — — — — — 4,374 SWEPCo — — — — — (9,470 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 734 0 I&M — (1,277 ) 0 OPCo — 1,282 0 PSO — 771 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. |
Collateral Required Under Various Triggering Events | September 30, 2015 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 2,913 $ 97 I&M — — 1,976 66 OPCo — — — — PSO — — 2,692 3,247 SWEPCo — — 3,328 58 December 31, 2014 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 6,339 $ 74 I&M — — 4,299 47 OPCo — — — — PSO — — 693 4,111 SWEPCo — — 877 166 |
Liabilities Subject to Cross Default Provisions | September 30, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 5,310 $ — $ 5,288 I&M 3,601 — 3,586 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 9,043 $ — $ 9,012 I&M 6,134 — 6,113 OPCo — — — PSO — — — SWEPCo — — — |
Ohio Power Co [Member] | |
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments September 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 62,306 30,345 13,470 17,580 21,736 Coal Tons 116 1,468 — — 2,125 Natural Gas MMBtus 256 174 — — — Heating Oil and Gasoline Gallons 1,763 836 1,858 1,019 1,166 Interest Rate USD $ 2,645 $ 1,794 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — |
Cash Collateral Netting | September 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 1,688 $ 68 $ 98 I&M — 333 163 47 OPCo — 500 — 102 PSO — 280 — 54 SWEPCo — 319 — 62 |
Fair Value of Derivative Instruments | OPCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ — $ — $ — $ — $ — $ — Long-term Risk Management Assets 23,265 — — 23,265 — 23,265 Total Assets 23,265 — — 23,265 — 23,265 Current Risk Management Liabilities 3,271 — — 3,271 (448 ) 2,823 Long-term Risk Management Liabilities 4,923 — — 4,923 (52 ) 4,871 Total Liabilities 8,194 — — 8,194 (500 ) 7,694 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,071 $ — $ — $ 15,071 $ 500 $ 15,571 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 7,242 $ — $ — $ 7,242 $ — $ 7,242 Long-term Risk Management Assets 45,102 — — 45,102 — 45,102 Total Assets 52,344 — — 52,344 — 52,344 Current Risk Management Liabilities 2,045 — — 2,045 (102 ) 1,943 Long-term Risk Management Liabilities 3,013 — — 3,013 — 3,013 Total Liabilities 5,058 — — 5,058 (102 ) 4,956 Total MTM Derivative Contract Net Assets (Liabilities) $ 47,286 $ — $ — $ 47,286 $ 102 $ 47,388 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
Amount of Gain (Loss) Recognized on Risk Management Contracts | Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ (369 ) $ 350 $ (917 ) $ (9 ) $ (7 ) Sales to AEP Affiliates 1,156 3,336 — — — Other Operation Expense (88 ) (63 ) (128 ) (109 ) (127 ) Maintenance Expense (164 ) (86 ) (140 ) (88 ) (88 ) Purchased Electricity for Resale 831 15 30 — — Regulatory Assets (a) 861 (981 ) — (190 ) 188 Regulatory Liabilities (a) 3,197 (1,718 ) (22,281 ) (498 ) 1,137 Total Gain (Loss) on Risk Management Contracts $ 5,424 $ 853 $ (23,436 ) $ (894 ) $ 1,103 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,231 $ 2,988 $ 41 $ 45 $ 74 Sales to AEP Affiliates — (196 ) — 196 — Regulatory Assets (a) (2,571 ) (471 ) (852 ) (109 ) (284 ) Regulatory Liabilities (a) (3,606 ) (176 ) (1,555 ) 120 (180 ) Total Gain (Loss) on Risk Management Contracts $ (4,946 ) $ 2,145 $ (2,366 ) $ 252 $ (390 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 790 $ 3,591 $ (882 ) $ 16 $ 19 Sales to AEP Affiliates 1,511 4,341 — — — Other Operation Expense (287 ) (221 ) (389 ) (307 ) (373 ) Maintenance Expense (503 ) (221 ) (396 ) (248 ) (265 ) Purchased Electricity for Resale 1,571 347 30 — — Regulatory Assets (a) 2,136 (1,213 ) — 615 (1,234 ) Regulatory Liabilities (a) 31,797 4,121 (24,880 ) 5,076 14,446 Total Gain (Loss) on Risk Management Contracts $ 37,015 $ 10,745 $ (26,517 ) $ 5,152 $ 12,593 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 7,262 $ 10,467 $ 97 $ 172 $ 18 Sales to AEP Affiliates — (717 ) — 717 — Regulatory Assets (a) (2,567 ) (471 ) (215 ) (119 ) (285 ) Regulatory Liabilities (a) 42,444 26,934 39,311 (69 ) 119 Total Gain (Loss) on Risk Management Contracts $ 47,139 $ 36,213 $ 39,193 $ 701 $ (148 ) (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets September 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,805 I&M — — — — — (13,604 ) OPCo — — — — — 4,572 PSO — — — — — 4,374 SWEPCo — — — — — (9,470 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 734 0 I&M — (1,277 ) 0 OPCo — 1,282 0 PSO — 771 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. |
Collateral Required Under Various Triggering Events | September 30, 2015 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 2,913 $ 97 I&M — — 1,976 66 OPCo — — — — PSO — — 2,692 3,247 SWEPCo — — 3,328 58 December 31, 2014 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 6,339 $ 74 I&M — — 4,299 47 OPCo — — — — PSO — — 693 4,111 SWEPCo — — 877 166 |
Liabilities Subject to Cross Default Provisions | September 30, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 5,310 $ — $ 5,288 I&M 3,601 — 3,586 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 9,043 $ — $ 9,012 I&M 6,134 — 6,113 OPCo — — — PSO — — — SWEPCo — — — |
Public Service Co Of Oklahoma [Member] | |
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments September 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 62,306 30,345 13,470 17,580 21,736 Coal Tons 116 1,468 — — 2,125 Natural Gas MMBtus 256 174 — — — Heating Oil and Gasoline Gallons 1,763 836 1,858 1,019 1,166 Interest Rate USD $ 2,645 $ 1,794 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — |
Cash Collateral Netting | September 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 1,688 $ 68 $ 98 I&M — 333 163 47 OPCo — 500 — 102 PSO — 280 — 54 SWEPCo — 319 — 62 |
Fair Value of Derivative Instruments | PSO Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,166 $ — $ — $ 1,166 $ (131 ) $ 1,035 Long-term Risk Management Assets — — — — — — Total Assets 1,166 — — 1,166 (131 ) 1,035 Current Risk Management Liabilities 454 — — 454 (384 ) 70 Long-term Risk Management Liabilities 35 — — 35 (27 ) 8 Total Liabilities 489 — — 489 (411 ) 78 Total MTM Derivative Contract Net Assets (Liabilities) $ 677 $ — $ — $ 677 $ 280 $ 957 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 360 $ — $ — $ 360 $ (360 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 360 — — 360 (360 ) — Current Risk Management Liabilities 1,332 — — 1,332 (414 ) 918 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,332 — — 1,332 (414 ) 918 Total MTM Derivative Contract Net Assets (Liabilities) $ (972 ) $ — $ — $ (972 ) $ 54 $ (918 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
Amount of Gain (Loss) Recognized on Risk Management Contracts | Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ (369 ) $ 350 $ (917 ) $ (9 ) $ (7 ) Sales to AEP Affiliates 1,156 3,336 — — — Other Operation Expense (88 ) (63 ) (128 ) (109 ) (127 ) Maintenance Expense (164 ) (86 ) (140 ) (88 ) (88 ) Purchased Electricity for Resale 831 15 30 — — Regulatory Assets (a) 861 (981 ) — (190 ) 188 Regulatory Liabilities (a) 3,197 (1,718 ) (22,281 ) (498 ) 1,137 Total Gain (Loss) on Risk Management Contracts $ 5,424 $ 853 $ (23,436 ) $ (894 ) $ 1,103 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,231 $ 2,988 $ 41 $ 45 $ 74 Sales to AEP Affiliates — (196 ) — 196 — Regulatory Assets (a) (2,571 ) (471 ) (852 ) (109 ) (284 ) Regulatory Liabilities (a) (3,606 ) (176 ) (1,555 ) 120 (180 ) Total Gain (Loss) on Risk Management Contracts $ (4,946 ) $ 2,145 $ (2,366 ) $ 252 $ (390 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 790 $ 3,591 $ (882 ) $ 16 $ 19 Sales to AEP Affiliates 1,511 4,341 — — — Other Operation Expense (287 ) (221 ) (389 ) (307 ) (373 ) Maintenance Expense (503 ) (221 ) (396 ) (248 ) (265 ) Purchased Electricity for Resale 1,571 347 30 — — Regulatory Assets (a) 2,136 (1,213 ) — 615 (1,234 ) Regulatory Liabilities (a) 31,797 4,121 (24,880 ) 5,076 14,446 Total Gain (Loss) on Risk Management Contracts $ 37,015 $ 10,745 $ (26,517 ) $ 5,152 $ 12,593 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 7,262 $ 10,467 $ 97 $ 172 $ 18 Sales to AEP Affiliates — (717 ) — 717 — Regulatory Assets (a) (2,567 ) (471 ) (215 ) (119 ) (285 ) Regulatory Liabilities (a) 42,444 26,934 39,311 (69 ) 119 Total Gain (Loss) on Risk Management Contracts $ 47,139 $ 36,213 $ 39,193 $ 701 $ (148 ) (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets September 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,805 I&M — — — — — (13,604 ) OPCo — — — — — 4,572 PSO — — — — — 4,374 SWEPCo — — — — — (9,470 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 734 0 I&M — (1,277 ) 0 OPCo — 1,282 0 PSO — 771 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. |
Collateral Required Under Various Triggering Events | September 30, 2015 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 2,913 $ 97 I&M — — 1,976 66 OPCo — — — — PSO — — 2,692 3,247 SWEPCo — — 3,328 58 December 31, 2014 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 6,339 $ 74 I&M — — 4,299 47 OPCo — — — — PSO — — 693 4,111 SWEPCo — — 877 166 |
Liabilities Subject to Cross Default Provisions | September 30, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 5,310 $ — $ 5,288 I&M 3,601 — 3,586 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 9,043 $ — $ 9,012 I&M 6,134 — 6,113 OPCo — — — PSO — — — SWEPCo — — — |
Southwestern Electric Power Co [Member] | |
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments September 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 62,306 30,345 13,470 17,580 21,736 Coal Tons 116 1,468 — — 2,125 Natural Gas MMBtus 256 174 — — — Heating Oil and Gasoline Gallons 1,763 836 1,858 1,019 1,166 Interest Rate USD $ 2,645 $ 1,794 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — |
Cash Collateral Netting | September 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 1,688 $ 68 $ 98 I&M — 333 163 47 OPCo — 500 — 102 PSO — 280 — 54 SWEPCo — 319 — 62 |
Fair Value of Derivative Instruments | SWEPCo Fair Value of Derivative Instruments September 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,442 $ — $ — $ 1,442 $ (162 ) $ 1,280 Long-term Risk Management Assets — — — — — — Total Assets 1,442 — — 1,442 (162 ) 1,280 Current Risk Management Liabilities 1,752 — — 1,752 (450 ) 1,302 Long-term Risk Management Liabilities 788 — — 788 (31 ) 757 Total Liabilities 2,540 — — 2,540 (481 ) 2,059 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,098 ) $ — $ — $ (1,098 ) $ 319 $ (779 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 471 $ — $ — $ 471 $ (440 ) $ 31 Long-term Risk Management Assets — — — — — — Total Assets 471 — — 471 (440 ) 31 Current Risk Management Liabilities 1,584 — — 1,584 (502 ) 1,082 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,584 — — 1,584 (502 ) 1,082 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,113 ) $ — $ — $ (1,113 ) $ 62 $ (1,051 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. |
Amount of Gain (Loss) Recognized on Risk Management Contracts | Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ (369 ) $ 350 $ (917 ) $ (9 ) $ (7 ) Sales to AEP Affiliates 1,156 3,336 — — — Other Operation Expense (88 ) (63 ) (128 ) (109 ) (127 ) Maintenance Expense (164 ) (86 ) (140 ) (88 ) (88 ) Purchased Electricity for Resale 831 15 30 — — Regulatory Assets (a) 861 (981 ) — (190 ) 188 Regulatory Liabilities (a) 3,197 (1,718 ) (22,281 ) (498 ) 1,137 Total Gain (Loss) on Risk Management Contracts $ 5,424 $ 853 $ (23,436 ) $ (894 ) $ 1,103 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,231 $ 2,988 $ 41 $ 45 $ 74 Sales to AEP Affiliates — (196 ) — 196 — Regulatory Assets (a) (2,571 ) (471 ) (852 ) (109 ) (284 ) Regulatory Liabilities (a) (3,606 ) (176 ) (1,555 ) 120 (180 ) Total Gain (Loss) on Risk Management Contracts $ (4,946 ) $ 2,145 $ (2,366 ) $ 252 $ (390 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 790 $ 3,591 $ (882 ) $ 16 $ 19 Sales to AEP Affiliates 1,511 4,341 — — — Other Operation Expense (287 ) (221 ) (389 ) (307 ) (373 ) Maintenance Expense (503 ) (221 ) (396 ) (248 ) (265 ) Purchased Electricity for Resale 1,571 347 30 — — Regulatory Assets (a) 2,136 (1,213 ) — 615 (1,234 ) Regulatory Liabilities (a) 31,797 4,121 (24,880 ) 5,076 14,446 Total Gain (Loss) on Risk Management Contracts $ 37,015 $ 10,745 $ (26,517 ) $ 5,152 $ 12,593 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Nine Months Ended September 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 7,262 $ 10,467 $ 97 $ 172 $ 18 Sales to AEP Affiliates — (717 ) — 717 — Regulatory Assets (a) (2,567 ) (471 ) (215 ) (119 ) (285 ) Regulatory Liabilities (a) 42,444 26,934 39,311 (69 ) 119 Total Gain (Loss) on Risk Management Contracts $ 47,139 $ 36,213 $ 39,193 $ 701 $ (148 ) (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets September 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,805 I&M — — — — — (13,604 ) OPCo — — — — — 4,572 PSO — — — — — 4,374 SWEPCo — — — — — (9,470 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 734 0 I&M — (1,277 ) 0 OPCo — 1,282 0 PSO — 771 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. |
Collateral Required Under Various Triggering Events | September 30, 2015 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 2,913 $ 97 I&M — — 1,976 66 OPCo — — — — PSO — — 2,692 3,247 SWEPCo — — 3,328 58 December 31, 2014 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 6,339 $ 74 I&M — — 4,299 47 OPCo — — — — PSO — — 693 4,111 SWEPCo — — 877 166 |
Liabilities Subject to Cross Default Provisions | September 30, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 5,310 $ — $ 5,288 I&M 3,601 — 3,586 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 9,043 $ — $ 9,012 I&M 6,134 — 6,113 OPCo — — — PSO — — — SWEPCo — — — |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Book Values and Fair Values of Long-term Debt | September 30, 2015 December 31, 2014 Book Value (a) Fair Value Book Value (a) Fair Value (in millions) Long-term Debt $ 19,507 $ 21,257 $ 18,684 $ 21,075 (a) Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. |
Other Temporary Investments | September 30, 2015 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 201 $ — $ — $ 201 Fixed Income Securities – Mutual Funds 90 — — 90 Equity Securities – Mutual Funds 14 10 — 24 Total Other Temporary Investments $ 305 $ 10 $ — $ 315 December 31, 2014 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 280 $ — $ — $ 280 Fixed Income Securities – Mutual Funds 81 — — 81 Equity Securities – Mutual Funds 13 12 — 25 Total Other Temporary Investments $ 374 $ 12 $ — $ 386 (a) Primarily represents amounts held for the repayment of debt. |
Debt and Equity Securities Within Other Temporary Investments | Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 10 — 10 1 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — |
Nuclear Trust Fund Investments | September 30, 2015 December 31, 2014 Fair Value Gross Unrealized Gains Other-Than- Temporary Fair Value Gross Unrealized Gains Other-Than- Temporary (in millions) Cash and Cash Equivalents $ 164 $ — $ — $ 20 $ — $ — Fixed Income Securities: United States Government 704 45 (2 ) 697 45 (5 ) Corporate Debt 62 4 (1 ) 48 4 (1 ) State and Local Government 50 1 — 208 1 — Subtotal Fixed Income Securities 816 50 (3 ) 953 50 (6 ) Equity Securities – Domestic 1,067 516 (80 ) 1,123 599 (79 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,047 $ 566 $ (83 ) $ 2,096 $ 649 $ (85 ) |
Securities Activity Within the Decommissioning and SNF Trusts | Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in millions) Proceeds from Investment Sales $ 921 $ 263 $ 1,437 $ 746 Purchases of Investments 938 281 1,479 790 Gross Realized Gains on Investment Sales 15 8 34 25 Gross Realized Losses on Investment Sales 13 1 23 10 |
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts | Fair Value of Securities (in millions) Within 1 year $ 166 1 year – 5 years 336 5 years – 10 years 140 After 10 years 174 Total $ 816 |
Fair Value, Assets and Liabilities Measured on Recurring Basis | Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 12 $ 4 $ — $ 162 $ 178 Other Temporary Investments Restricted Cash (a) 189 6 — 6 201 Fixed Income Securities - Mutual Funds 90 — — — 90 Equity Securities – Mutual Funds (b) 24 — — — 24 Total Other Temporary Investments 303 6 — 6 315 Risk Management Assets Risk Management Commodity Contracts (c) (d) 17 478 248 (256 ) 487 Cash Flow Hedges: Commodity Hedges (c) — 10 1 (4 ) 7 Fair Value Hedges — 1 — 1 2 Total Risk Management Assets 17 489 249 (259 ) 496 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 157 — — 7 164 Fixed Income Securities: United States Government — 704 — — 704 Corporate Debt — 62 — — 62 State and Local Government — 50 — — 50 Subtotal Fixed Income Securities — 816 — — 816 Equity Securities – Domestic (b) 1,067 — — — 1,067 Total Spent Nuclear Fuel and Decommissioning Trusts 1,224 816 — 7 2,047 Total Assets $ 1,556 $ 1,315 $ 249 $ (84 ) $ 3,036 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 33 $ 440 $ 76 $ (299 ) $ 250 Cash Flow Hedges: Commodity Hedges (c) — 22 6 (4 ) 24 Interest Rate/Foreign Currency Hedges — 1 — — 1 Fair Value Hedges — — — 1 1 Total Risk Management Liabilities $ 33 $ 463 $ 82 $ (302 ) $ 276 Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17 $ 1 $ — $ 145 $ 163 Other Temporary Investments Restricted Cash (a) 234 9 — 37 280 Fixed Income Securities - Mutual Funds 81 — — — 81 Equity Securities – Mutual Funds (b) 25 — — — 25 Total Other Temporary Investments 340 9 — 37 386 Risk Management Assets Risk Management Commodity Contracts (c) (f) 37 528 190 (302 ) 453 Cash Flow Hedges: Commodity Hedges (c) — 32 — (16 ) 16 Fair Value Hedges — 1 — 2 3 Total Risk Management Assets 37 561 190 (316 ) 472 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9 — — 11 20 Fixed Income Securities: United States Government — 697 — — 697 Corporate Debt — 48 — — 48 State and Local Government — 208 — — 208 Subtotal Fixed Income Securities — 953 — — 953 Equity Securities – Domestic (b) 1,123 — — — 1,123 Total Spent Nuclear Fuel and Decommissioning Trusts 1,132 953 — 11 2,096 Total Assets $ 1,526 $ 1,524 $ 190 $ (123 ) $ 3,117 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 65 $ 432 $ 36 $ (334 ) $ 199 Cash Flow Hedges: Commodity Hedges (c) — 27 3 (16 ) 14 Interest Rate/Foreign Currency Hedges — 1 — — 1 Fair Value Hedges — 7 — 2 9 Total Risk Management Liabilities $ 65 $ 467 $ 39 $ (348 ) $ 223 (a) Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.'' (d) The September 30, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($4) million in 2015 and ($12) million in periods 2016-2018; Level 2 matures $5 million in 2015 , $28 million in periods 2016-2018, $3 million in periods 2019-2020 and $2 million in periods 2021-2032; Level 3 matures $2 million in 2015 , $63 million in periods 2016-2018, $25 million in periods 2019-2020 and $82 million in periods 2021-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $31 million in 2015 , $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015 , $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. |
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended September 30, 2015 Net Risk Management Assets (Liabilities) (in millions) Balance as of June 30, 2015 $ 203 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 11 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 6 Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2 ) Purchases, Issuances and Settlements (c) (29 ) Transfers into Level 3 (d) (e) 8 Transfers out of Level 3 (e) (f) (5 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) (25 ) Balance as of September 30, 2015 $ 167 Three Months Ended September 30, 2014 Net Risk Management (in millions) Balance as of June 30, 2014 $ 132 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (9 ) Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 10 Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (3 ) Purchases, Issuances and Settlements (c) (5 ) Transfers into Level 3 (d) (e) (9 ) Transfers out of Level 3 (e) (f) (1 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14 Balance as of September 30, 2014 $ 129 Nine Months Ended September 30, 2015 Net Risk Management (in millions) Balance as of December 31, 2014 $ 151 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 14 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 54 Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4 ) Purchases, Issuances and Settlements (c) (60 ) Transfers into Level 3 (d) (e) 28 Transfers out of Level 3 (e) (f) (17 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 1 Balance as of September 30, 2015 $ 167 Nine Months Ended September 30, 2014 Net Risk Management (in millions) Balance as of December 31, 2013 $ 117 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 91 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (3 ) Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12 Purchases, Issuances and Settlements (c) (103 ) Transfers into Level 3 (d) (e) (9 ) Transfers out of Level 3 (e) (f) (8 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 32 Balance as of September 30, 2014 $ 129 (a) Included in revenues on the condensed statements of income. (b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (c) Represents the settlement of risk management commodity contracts for the reporting period. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Represents existing assets or liabilities that were previously categorized as Level 3. (g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. |
Significant Unobservable Inputs for Level 3 | Significant Unobservable Inputs September 30, 2015 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 226 $ 79 Discounted Cash Flow Forward Market Price (a) $ 13.03 $ 165.93 $ 36.37 Counterparty Credit Risk (b) 481 FTRs 23 3 Discounted Cash Flow Forward Market Price (a) (10.67 ) 11.60 1.31 Total $ 249 $ 82 Significant Unobservable Inputs December 31, 2014 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157 $ 37 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33 2 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190 $ 39 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. |
Sensitivity of Fair Value Measurements | Sensitivity of Fair Value Measurements September 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher) |
Appalachian Power Co [Member] | |
Book Values and Fair Values of Long-term Debt | September 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,955,295 $ 4,460,140 $ 3,980,274 $ 4,711,210 I&M 2,060,651 2,241,930 2,027,397 2,255,124 OPCo 2,166,050 2,502,105 2,297,123 2,709,452 PSO 1,290,973 1,424,300 1,041,036 1,216,205 SWEPCo 2,283,966 2,446,716 2,140,437 2,402,639 |
Nuclear Trust Fund Investments | September 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 164,353 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 704,344 45,005 (2,291 ) 697,042 44,615 (5,016 ) Corporate Debt 62,118 3,682 (1,043 ) 47,792 4,523 (1,018 ) State and Local Government 50,018 996 (324 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 816,480 49,683 (3,658 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,066,427 516,206 (80,280 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,047,260 $ 565,889 $ (83,938 ) $ 2,095,732 $ 649,132 $ (85,495 ) |
Securities Activity Within the Decommissioning and SNF Trusts | Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 921,552 $ 263,738 $ 1,437,336 $ 746,272 Purchases of Investments 938,438 280,626 1,479,149 789,461 Gross Realized Gains on Investment Sales 15,030 7,617 33,840 24,835 Gross Realized Losses on Investment Sales 13,167 1,739 22,823 10,447 |
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts | Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 166,336 1 year – 5 years 335,823 5 years – 10 years 140,129 After 10 years 174,192 Total $ 816,480 |
Fair Value, Assets and Liabilities Measured on Recurring Basis | APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 7,436 $ — $ — $ 57 $ 7,493 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) 185 12,785 23,743 (7,328 ) 29,385 Total Assets: $ 7,621 $ 12,785 $ 23,743 $ (7,271 ) $ 36,878 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 198 $ 16,031 $ 662 $ (9,016 ) $ 7,875 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) $ 126 $ 10,347 $ 7,795 $ (6,303 ) $ 11,965 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 157,409 — — 6,944 164,353 Fixed Income Securities: United States Government — 704,344 — — 704,344 Corporate Debt — 62,118 — — 62,118 State and Local Government — 50,018 — — 50,018 Subtotal Fixed Income Securities — 816,480 — — 816,480 Equity Securities - Domestic (e) 1,066,427 — — — 1,066,427 Total Spent Nuclear Fuel and Decommissioning Trusts 1,223,836 816,480 — 6,944 2,047,260 Total Assets $ 1,223,962 $ 826,827 $ 7,795 $ 641 $ 2,059,225 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 135 $ 10,945 $ 1,419 $ (6,636 ) $ 5,863 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 16,195 $ — $ — $ 9 $ 16,204 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 20,719 2,546 23,265 Total Assets $ 16,195 $ — $ 20,719 $ 2,555 $ 39,469 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 639 $ 5,009 $ 2,046 $ 7,694 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 1,166 $ (131 ) $ 1,035 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 358 $ 131 $ (411 ) $ 78 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 11,688 $ — $ — $ 2,570 $ 14,258 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 1,442 (162 ) 1,280 Total Assets $ 11,688 $ — $ 1,442 $ 2,408 $ 15,538 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 2,378 $ 162 $ (481 ) $ 2,059 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. (d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (e) Amounts represent publicly traded equity securities and equity-based mutual funds. |
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 5,065 885 (28 ) (280 ) 2,366 Purchases, Issuances and Settlements (d) (13,965 ) (3,604 ) 348 (176 ) (2,912 ) Changes in Fair Value Allocated to Regulated Jurisdictions (h) (1,855 ) (2,749 ) (22,267 ) (208 ) (213 ) Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Three Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (5,629 ) (3,832 ) (3,639 ) 2 2 Purchases, Issuances and Settlements (d) (1,560 ) (1,244 ) (637 ) — — Transfers into Level 3 (e) (f) (6 ) (4 ) — — — Transfers out of Level 3 (f) (g) (30 ) (20 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 4,843 4,319 2,865 335 409 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 Nine Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 1,757 (193 ) 1,182 (176 ) 9,187 Purchases, Issuances and Settlements (d) (16,124 ) (12,807 ) (7,906 ) 553 (8,727 ) Transfers out of Level 3 (f) (g) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 20,539 3,880 (25,968 ) 1,035 1,280 Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Nine Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2013 $ 10,562 $ 7,164 $ 2,920 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 29,467 18,438 30,768 — — Purchases, Issuances and Settlements (d) (32,213 ) (20,301 ) (33,688 ) — — Transfers into Level 3 (e) (f) (3,648 ) (2,475 ) — — — Transfers out of Level 3 (f) (g) (32 ) (22 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 11,876 9,338 7,889 334 408 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the condensed statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. |
Significant Unobservable Inputs for Level 3 | Significant Unobservable Inputs September 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 8,724 $ 451 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 15,019 211 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 23,743 $ 662 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs September 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 7,147 $ 295 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 648 1,124 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 7,795 $ 1,419 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs September 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 20,719 $ 5,009 Discounted Cash Flow Forward Market Price $ 35.71 $ 165.93 $ 85.99 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52,343 $ 3,941 Significant Unobservable Inputs September 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,166 $ 131 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs September 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,442 $ 162 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. |
Sensitivity of Fair Value Measurements | Sensitivity of Fair Value Measurements September 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) |
Indiana Michigan Power Co [Member] | |
Book Values and Fair Values of Long-term Debt | September 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,955,295 $ 4,460,140 $ 3,980,274 $ 4,711,210 I&M 2,060,651 2,241,930 2,027,397 2,255,124 OPCo 2,166,050 2,502,105 2,297,123 2,709,452 PSO 1,290,973 1,424,300 1,041,036 1,216,205 SWEPCo 2,283,966 2,446,716 2,140,437 2,402,639 |
Nuclear Trust Fund Investments | September 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 164,353 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 704,344 45,005 (2,291 ) 697,042 44,615 (5,016 ) Corporate Debt 62,118 3,682 (1,043 ) 47,792 4,523 (1,018 ) State and Local Government 50,018 996 (324 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 816,480 49,683 (3,658 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,066,427 516,206 (80,280 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,047,260 $ 565,889 $ (83,938 ) $ 2,095,732 $ 649,132 $ (85,495 ) |
Securities Activity Within the Decommissioning and SNF Trusts | Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 921,552 $ 263,738 $ 1,437,336 $ 746,272 Purchases of Investments 938,438 280,626 1,479,149 789,461 Gross Realized Gains on Investment Sales 15,030 7,617 33,840 24,835 Gross Realized Losses on Investment Sales 13,167 1,739 22,823 10,447 |
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts | Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 166,336 1 year – 5 years 335,823 5 years – 10 years 140,129 After 10 years 174,192 Total $ 816,480 |
Fair Value, Assets and Liabilities Measured on Recurring Basis | APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 7,436 $ — $ — $ 57 $ 7,493 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) 185 12,785 23,743 (7,328 ) 29,385 Total Assets: $ 7,621 $ 12,785 $ 23,743 $ (7,271 ) $ 36,878 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 198 $ 16,031 $ 662 $ (9,016 ) $ 7,875 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) $ 126 $ 10,347 $ 7,795 $ (6,303 ) $ 11,965 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 157,409 — — 6,944 164,353 Fixed Income Securities: United States Government — 704,344 — — 704,344 Corporate Debt — 62,118 — — 62,118 State and Local Government — 50,018 — — 50,018 Subtotal Fixed Income Securities — 816,480 — — 816,480 Equity Securities - Domestic (e) 1,066,427 — — — 1,066,427 Total Spent Nuclear Fuel and Decommissioning Trusts 1,223,836 816,480 — 6,944 2,047,260 Total Assets $ 1,223,962 $ 826,827 $ 7,795 $ 641 $ 2,059,225 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 135 $ 10,945 $ 1,419 $ (6,636 ) $ 5,863 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 16,195 $ — $ — $ 9 $ 16,204 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 20,719 2,546 23,265 Total Assets $ 16,195 $ — $ 20,719 $ 2,555 $ 39,469 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 639 $ 5,009 $ 2,046 $ 7,694 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 1,166 $ (131 ) $ 1,035 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 358 $ 131 $ (411 ) $ 78 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 11,688 $ — $ — $ 2,570 $ 14,258 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 1,442 (162 ) 1,280 Total Assets $ 11,688 $ — $ 1,442 $ 2,408 $ 15,538 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 2,378 $ 162 $ (481 ) $ 2,059 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. (d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (e) Amounts represent publicly traded equity securities and equity-based mutual funds. |
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 5,065 885 (28 ) (280 ) 2,366 Purchases, Issuances and Settlements (d) (13,965 ) (3,604 ) 348 (176 ) (2,912 ) Changes in Fair Value Allocated to Regulated Jurisdictions (h) (1,855 ) (2,749 ) (22,267 ) (208 ) (213 ) Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Three Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (5,629 ) (3,832 ) (3,639 ) 2 2 Purchases, Issuances and Settlements (d) (1,560 ) (1,244 ) (637 ) — — Transfers into Level 3 (e) (f) (6 ) (4 ) — — — Transfers out of Level 3 (f) (g) (30 ) (20 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 4,843 4,319 2,865 335 409 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 Nine Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 1,757 (193 ) 1,182 (176 ) 9,187 Purchases, Issuances and Settlements (d) (16,124 ) (12,807 ) (7,906 ) 553 (8,727 ) Transfers out of Level 3 (f) (g) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 20,539 3,880 (25,968 ) 1,035 1,280 Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Nine Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2013 $ 10,562 $ 7,164 $ 2,920 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 29,467 18,438 30,768 — — Purchases, Issuances and Settlements (d) (32,213 ) (20,301 ) (33,688 ) — — Transfers into Level 3 (e) (f) (3,648 ) (2,475 ) — — — Transfers out of Level 3 (f) (g) (32 ) (22 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 11,876 9,338 7,889 334 408 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the condensed statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. |
Significant Unobservable Inputs for Level 3 | Significant Unobservable Inputs September 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 8,724 $ 451 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 15,019 211 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 23,743 $ 662 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs September 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 7,147 $ 295 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 648 1,124 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 7,795 $ 1,419 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs September 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 20,719 $ 5,009 Discounted Cash Flow Forward Market Price $ 35.71 $ 165.93 $ 85.99 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52,343 $ 3,941 Significant Unobservable Inputs September 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,166 $ 131 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs September 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,442 $ 162 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. |
Sensitivity of Fair Value Measurements | Sensitivity of Fair Value Measurements September 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) |
Ohio Power Co [Member] | |
Book Values and Fair Values of Long-term Debt | September 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,955,295 $ 4,460,140 $ 3,980,274 $ 4,711,210 I&M 2,060,651 2,241,930 2,027,397 2,255,124 OPCo 2,166,050 2,502,105 2,297,123 2,709,452 PSO 1,290,973 1,424,300 1,041,036 1,216,205 SWEPCo 2,283,966 2,446,716 2,140,437 2,402,639 |
Nuclear Trust Fund Investments | September 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 164,353 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 704,344 45,005 (2,291 ) 697,042 44,615 (5,016 ) Corporate Debt 62,118 3,682 (1,043 ) 47,792 4,523 (1,018 ) State and Local Government 50,018 996 (324 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 816,480 49,683 (3,658 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,066,427 516,206 (80,280 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,047,260 $ 565,889 $ (83,938 ) $ 2,095,732 $ 649,132 $ (85,495 ) |
Securities Activity Within the Decommissioning and SNF Trusts | Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 921,552 $ 263,738 $ 1,437,336 $ 746,272 Purchases of Investments 938,438 280,626 1,479,149 789,461 Gross Realized Gains on Investment Sales 15,030 7,617 33,840 24,835 Gross Realized Losses on Investment Sales 13,167 1,739 22,823 10,447 |
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts | Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 166,336 1 year – 5 years 335,823 5 years – 10 years 140,129 After 10 years 174,192 Total $ 816,480 |
Fair Value, Assets and Liabilities Measured on Recurring Basis | APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 7,436 $ — $ — $ 57 $ 7,493 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) 185 12,785 23,743 (7,328 ) 29,385 Total Assets: $ 7,621 $ 12,785 $ 23,743 $ (7,271 ) $ 36,878 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 198 $ 16,031 $ 662 $ (9,016 ) $ 7,875 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) $ 126 $ 10,347 $ 7,795 $ (6,303 ) $ 11,965 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 157,409 — — 6,944 164,353 Fixed Income Securities: United States Government — 704,344 — — 704,344 Corporate Debt — 62,118 — — 62,118 State and Local Government — 50,018 — — 50,018 Subtotal Fixed Income Securities — 816,480 — — 816,480 Equity Securities - Domestic (e) 1,066,427 — — — 1,066,427 Total Spent Nuclear Fuel and Decommissioning Trusts 1,223,836 816,480 — 6,944 2,047,260 Total Assets $ 1,223,962 $ 826,827 $ 7,795 $ 641 $ 2,059,225 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 135 $ 10,945 $ 1,419 $ (6,636 ) $ 5,863 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 16,195 $ — $ — $ 9 $ 16,204 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 20,719 2,546 23,265 Total Assets $ 16,195 $ — $ 20,719 $ 2,555 $ 39,469 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 639 $ 5,009 $ 2,046 $ 7,694 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 1,166 $ (131 ) $ 1,035 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 358 $ 131 $ (411 ) $ 78 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 11,688 $ — $ — $ 2,570 $ 14,258 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 1,442 (162 ) 1,280 Total Assets $ 11,688 $ — $ 1,442 $ 2,408 $ 15,538 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 2,378 $ 162 $ (481 ) $ 2,059 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. (d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (e) Amounts represent publicly traded equity securities and equity-based mutual funds. |
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 5,065 885 (28 ) (280 ) 2,366 Purchases, Issuances and Settlements (d) (13,965 ) (3,604 ) 348 (176 ) (2,912 ) Changes in Fair Value Allocated to Regulated Jurisdictions (h) (1,855 ) (2,749 ) (22,267 ) (208 ) (213 ) Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Three Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (5,629 ) (3,832 ) (3,639 ) 2 2 Purchases, Issuances and Settlements (d) (1,560 ) (1,244 ) (637 ) — — Transfers into Level 3 (e) (f) (6 ) (4 ) — — — Transfers out of Level 3 (f) (g) (30 ) (20 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 4,843 4,319 2,865 335 409 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 Nine Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 1,757 (193 ) 1,182 (176 ) 9,187 Purchases, Issuances and Settlements (d) (16,124 ) (12,807 ) (7,906 ) 553 (8,727 ) Transfers out of Level 3 (f) (g) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 20,539 3,880 (25,968 ) 1,035 1,280 Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Nine Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2013 $ 10,562 $ 7,164 $ 2,920 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 29,467 18,438 30,768 — — Purchases, Issuances and Settlements (d) (32,213 ) (20,301 ) (33,688 ) — — Transfers into Level 3 (e) (f) (3,648 ) (2,475 ) — — — Transfers out of Level 3 (f) (g) (32 ) (22 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 11,876 9,338 7,889 334 408 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the condensed statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. |
Significant Unobservable Inputs for Level 3 | Significant Unobservable Inputs September 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 8,724 $ 451 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 15,019 211 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 23,743 $ 662 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs September 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 7,147 $ 295 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 648 1,124 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 7,795 $ 1,419 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs September 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 20,719 $ 5,009 Discounted Cash Flow Forward Market Price $ 35.71 $ 165.93 $ 85.99 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52,343 $ 3,941 Significant Unobservable Inputs September 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,166 $ 131 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs September 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,442 $ 162 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. |
Sensitivity of Fair Value Measurements | Sensitivity of Fair Value Measurements September 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) |
Public Service Co Of Oklahoma [Member] | |
Book Values and Fair Values of Long-term Debt | September 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,955,295 $ 4,460,140 $ 3,980,274 $ 4,711,210 I&M 2,060,651 2,241,930 2,027,397 2,255,124 OPCo 2,166,050 2,502,105 2,297,123 2,709,452 PSO 1,290,973 1,424,300 1,041,036 1,216,205 SWEPCo 2,283,966 2,446,716 2,140,437 2,402,639 |
Nuclear Trust Fund Investments | September 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 164,353 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 704,344 45,005 (2,291 ) 697,042 44,615 (5,016 ) Corporate Debt 62,118 3,682 (1,043 ) 47,792 4,523 (1,018 ) State and Local Government 50,018 996 (324 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 816,480 49,683 (3,658 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,066,427 516,206 (80,280 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,047,260 $ 565,889 $ (83,938 ) $ 2,095,732 $ 649,132 $ (85,495 ) |
Securities Activity Within the Decommissioning and SNF Trusts | Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 921,552 $ 263,738 $ 1,437,336 $ 746,272 Purchases of Investments 938,438 280,626 1,479,149 789,461 Gross Realized Gains on Investment Sales 15,030 7,617 33,840 24,835 Gross Realized Losses on Investment Sales 13,167 1,739 22,823 10,447 |
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts | Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 166,336 1 year – 5 years 335,823 5 years – 10 years 140,129 After 10 years 174,192 Total $ 816,480 |
Fair Value, Assets and Liabilities Measured on Recurring Basis | APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 7,436 $ — $ — $ 57 $ 7,493 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) 185 12,785 23,743 (7,328 ) 29,385 Total Assets: $ 7,621 $ 12,785 $ 23,743 $ (7,271 ) $ 36,878 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 198 $ 16,031 $ 662 $ (9,016 ) $ 7,875 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) $ 126 $ 10,347 $ 7,795 $ (6,303 ) $ 11,965 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 157,409 — — 6,944 164,353 Fixed Income Securities: United States Government — 704,344 — — 704,344 Corporate Debt — 62,118 — — 62,118 State and Local Government — 50,018 — — 50,018 Subtotal Fixed Income Securities — 816,480 — — 816,480 Equity Securities - Domestic (e) 1,066,427 — — — 1,066,427 Total Spent Nuclear Fuel and Decommissioning Trusts 1,223,836 816,480 — 6,944 2,047,260 Total Assets $ 1,223,962 $ 826,827 $ 7,795 $ 641 $ 2,059,225 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 135 $ 10,945 $ 1,419 $ (6,636 ) $ 5,863 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 16,195 $ — $ — $ 9 $ 16,204 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 20,719 2,546 23,265 Total Assets $ 16,195 $ — $ 20,719 $ 2,555 $ 39,469 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 639 $ 5,009 $ 2,046 $ 7,694 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 1,166 $ (131 ) $ 1,035 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 358 $ 131 $ (411 ) $ 78 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 11,688 $ — $ — $ 2,570 $ 14,258 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 1,442 (162 ) 1,280 Total Assets $ 11,688 $ — $ 1,442 $ 2,408 $ 15,538 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 2,378 $ 162 $ (481 ) $ 2,059 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. (d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (e) Amounts represent publicly traded equity securities and equity-based mutual funds. |
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 5,065 885 (28 ) (280 ) 2,366 Purchases, Issuances and Settlements (d) (13,965 ) (3,604 ) 348 (176 ) (2,912 ) Changes in Fair Value Allocated to Regulated Jurisdictions (h) (1,855 ) (2,749 ) (22,267 ) (208 ) (213 ) Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Three Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (5,629 ) (3,832 ) (3,639 ) 2 2 Purchases, Issuances and Settlements (d) (1,560 ) (1,244 ) (637 ) — — Transfers into Level 3 (e) (f) (6 ) (4 ) — — — Transfers out of Level 3 (f) (g) (30 ) (20 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 4,843 4,319 2,865 335 409 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 Nine Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 1,757 (193 ) 1,182 (176 ) 9,187 Purchases, Issuances and Settlements (d) (16,124 ) (12,807 ) (7,906 ) 553 (8,727 ) Transfers out of Level 3 (f) (g) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 20,539 3,880 (25,968 ) 1,035 1,280 Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Nine Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2013 $ 10,562 $ 7,164 $ 2,920 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 29,467 18,438 30,768 — — Purchases, Issuances and Settlements (d) (32,213 ) (20,301 ) (33,688 ) — — Transfers into Level 3 (e) (f) (3,648 ) (2,475 ) — — — Transfers out of Level 3 (f) (g) (32 ) (22 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 11,876 9,338 7,889 334 408 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the condensed statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. |
Significant Unobservable Inputs for Level 3 | Significant Unobservable Inputs September 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 8,724 $ 451 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 15,019 211 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 23,743 $ 662 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs September 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 7,147 $ 295 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 648 1,124 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 7,795 $ 1,419 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs September 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 20,719 $ 5,009 Discounted Cash Flow Forward Market Price $ 35.71 $ 165.93 $ 85.99 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52,343 $ 3,941 Significant Unobservable Inputs September 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,166 $ 131 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs September 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,442 $ 162 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. |
Sensitivity of Fair Value Measurements | Sensitivity of Fair Value Measurements September 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) |
Southwestern Electric Power Co [Member] | |
Book Values and Fair Values of Long-term Debt | September 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,955,295 $ 4,460,140 $ 3,980,274 $ 4,711,210 I&M 2,060,651 2,241,930 2,027,397 2,255,124 OPCo 2,166,050 2,502,105 2,297,123 2,709,452 PSO 1,290,973 1,424,300 1,041,036 1,216,205 SWEPCo 2,283,966 2,446,716 2,140,437 2,402,639 |
Nuclear Trust Fund Investments | September 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 164,353 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 704,344 45,005 (2,291 ) 697,042 44,615 (5,016 ) Corporate Debt 62,118 3,682 (1,043 ) 47,792 4,523 (1,018 ) State and Local Government 50,018 996 (324 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 816,480 49,683 (3,658 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,066,427 516,206 (80,280 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,047,260 $ 565,889 $ (83,938 ) $ 2,095,732 $ 649,132 $ (85,495 ) |
Securities Activity Within the Decommissioning and SNF Trusts | Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 921,552 $ 263,738 $ 1,437,336 $ 746,272 Purchases of Investments 938,438 280,626 1,479,149 789,461 Gross Realized Gains on Investment Sales 15,030 7,617 33,840 24,835 Gross Realized Losses on Investment Sales 13,167 1,739 22,823 10,447 |
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts | Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 166,336 1 year – 5 years 335,823 5 years – 10 years 140,129 After 10 years 174,192 Total $ 816,480 |
Fair Value, Assets and Liabilities Measured on Recurring Basis | APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 7,436 $ — $ — $ 57 $ 7,493 Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) 185 12,785 23,743 (7,328 ) 29,385 Total Assets: $ 7,621 $ 12,785 $ 23,743 $ (7,271 ) $ 36,878 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 198 $ 16,031 $ 662 $ (9,016 ) $ 7,875 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (b) (c) $ 126 $ 10,347 $ 7,795 $ (6,303 ) $ 11,965 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 157,409 — — 6,944 164,353 Fixed Income Securities: United States Government — 704,344 — — 704,344 Corporate Debt — 62,118 — — 62,118 State and Local Government — 50,018 — — 50,018 Subtotal Fixed Income Securities — 816,480 — — 816,480 Equity Securities - Domestic (e) 1,066,427 — — — 1,066,427 Total Spent Nuclear Fuel and Decommissioning Trusts 1,223,836 816,480 — 6,944 2,047,260 Total Assets $ 1,223,962 $ 826,827 $ 7,795 $ 641 $ 2,059,225 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 135 $ 10,945 $ 1,419 $ (6,636 ) $ 5,863 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 16,195 $ — $ — $ 9 $ 16,204 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 20,719 2,546 23,265 Total Assets $ 16,195 $ — $ 20,719 $ 2,555 $ 39,469 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 639 $ 5,009 $ 2,046 $ 7,694 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 1,166 $ (131 ) $ 1,035 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 358 $ 131 $ (411 ) $ 78 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis September 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 11,688 $ — $ — $ 2,570 $ 14,258 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 1,442 (162 ) 1,280 Total Assets $ 11,688 $ — $ 1,442 $ 2,408 $ 15,538 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 2,378 $ 162 $ (481 ) $ 2,059 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. (d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (e) Amounts represent publicly traded equity securities and equity-based mutual funds. |
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 5,065 885 (28 ) (280 ) 2,366 Purchases, Issuances and Settlements (d) (13,965 ) (3,604 ) 348 (176 ) (2,912 ) Changes in Fair Value Allocated to Regulated Jurisdictions (h) (1,855 ) (2,749 ) (22,267 ) (208 ) (213 ) Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Three Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) (5,629 ) (3,832 ) (3,639 ) 2 2 Purchases, Issuances and Settlements (d) (1,560 ) (1,244 ) (637 ) — — Transfers into Level 3 (e) (f) (6 ) (4 ) — — — Transfers out of Level 3 (f) (g) (30 ) (20 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 4,843 4,319 2,865 335 409 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 Nine Months Ended September 30, 2015 APCo (a) I&M (a) OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 1,757 (193 ) 1,182 (176 ) 9,187 Purchases, Issuances and Settlements (d) (16,124 ) (12,807 ) (7,906 ) 553 (8,727 ) Transfers out of Level 3 (f) (g) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 20,539 3,880 (25,968 ) 1,035 1,280 Balance as of September 30, 2015 $ 23,081 $ 6,376 $ 15,710 $ 1,035 $ 1,280 Nine Months Ended September 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2013 $ 10,562 $ 7,164 $ 2,920 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 29,467 18,438 30,768 — — Purchases, Issuances and Settlements (d) (32,213 ) (20,301 ) (33,688 ) — — Transfers into Level 3 (e) (f) (3,648 ) (2,475 ) — — — Transfers out of Level 3 (f) (g) (32 ) (22 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (h) 11,876 9,338 7,889 334 408 Balance as of September 30, 2014 $ 16,012 $ 12,142 $ 7,889 $ 334 $ 408 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the condensed statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents the settlement of risk management commodity contracts for the reporting period. (e) Represents existing assets or liabilities that were previously categorized as Level 2. (f) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (g) Represents existing assets or liabilities that were previously categorized as Level 3. (h) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. |
Significant Unobservable Inputs for Level 3 | Significant Unobservable Inputs September 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 8,724 $ 451 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 15,019 211 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 23,743 $ 662 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs September 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 7,147 $ 295 Discounted Cash Flow Forward Market Price $ 13.03 $ 48.17 $ 34.76 FTRs 648 1,124 Discounted Cash Flow Forward Market Price (5.95 ) 11.60 1.53 Total $ 7,795 $ 1,419 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs September 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 20,719 $ 5,009 Discounted Cash Flow Forward Market Price $ 35.71 $ 165.93 $ 85.99 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 52,343 $ 3,941 Significant Unobservable Inputs September 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,166 $ 131 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs September 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,442 $ 162 Discounted Cash Flow Forward Market Price $ (5.95 ) $ 11.60 $ 1.53 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. |
Sensitivity of Fair Value Measurements | Sensitivity of Fair Value Measurements September 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) |
Financing Activities (Tables)
Financing Activities (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Long-term Debt | Type of Debt September 30, 2015 December 31, 2014 (in millions) Senior Unsecured Notes $ 13,801 $ 12,647 Pollution Control Bonds 1,874 1,963 Notes Payable (a) 374 357 Securitization Bonds 2,072 2,380 Spent Nuclear Fuel Obligation (b) 266 266 Other Long-term Debt 1,151 1,101 Fair Value of Interest Rate Hedges — (6 ) Unamortized Discount, Net (31 ) (24 ) Total Long-term Debt Outstanding (a) 19,507 18,684 Long-term Debt Due Within One Year (a) 1,907 2,503 Long-term Debt (a) $ 17,600 $ 16,181 (a) Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. (b) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2015 and December 31, 2014 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the condensed balance sheets. |
Long-term Debt Issuances | Company Type of Debt Principal Amount Interest Rate Due Date Issuances: (in millions) (%) APCo Pollution Control Bonds $ 86 1.90 2019 APCo Senior Unsecured Notes 350 4.45 2045 APCo Senior Unsecured Notes 300 3.40 2025 I&M Notes Payable 111 Variable 2019 I&M Other Long-term Debt 100 Variable 2018 PSO Senior Unsecured Notes 125 3.17 2025 PSO Senior Unsecured Notes 125 4.09 2045 SWEPCo Pollution Control Bonds 54 1.60 2019 SWEPCo Senior Unsecured Notes 400 3.90 2045 Non-Registrant: AEPTCo Senior Unsecured Notes 60 4.01 2030 AEPTCo Senior Unsecured Notes 50 3.66 2025 AEPTCo Senior Unsecured Notes 40 3.76 2025 AGR Other Long-term Debt 500 Variable 2017 KPCo Other Long-term Debt 25 Variable 2018 TCC Senior Unsecured Notes 250 3.85 2025 TNC Senior Unsecured Notes 50 3.75 2025 TNC Senior Unsecured Notes 25 3.27 2022 Transource Missouri Other Long-term Debt 20 Variable 2018 WPCo Senior Unsecured Notes 113 3.36 2022 WPCo Senior Unsecured Notes 122 3.70 2025 WPCo Senior Unsecured Notes 50 4.20 2035 Total Issuances $ 2,956 (a) (a) Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the issuance amount. |
Retirements and Principal Payments | Company Type of Debt Principal Amount Paid Interest Due Date Total Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 23 2.008 2024 APCo Senior Unsecured Notes 350 7.95 2020 APCo Senior Unsecured Notes 300 3.40 2015 I&M Other Long-term Debt 94 Variable 2015 I&M Other Long-term Debt 1 6.00 2025 I&M Notes Payable 18 Variable 2016 I&M Notes Payable 21 Variable 2017 I&M Notes Payable 26 Variable 2019 I&M Notes Payable 16 Variable 2019 I&M Notes Payable 1 Variable 2016 I&M Notes Payable 1 2.12 2016 OPCo Pollution Control Bonds 86 3.125 2015 OPCo Securitization Bonds 45 0.958 2018 SWEPCo Notes Payable 3 4.58 2032 SWEPCo Pollution Control Bonds 54 3.25 2015 SWEPCo Senior Unsecured Notes 100 5.375 2015 SWEPCo Senior Unsecured Notes 150 4.90 2015 Non-Registrant: AEGCo Senior Unsecured Notes 7 6.33 2037 AEP Subsidiaries Notes Payable 5 Variable 2017 AEP Subsidiaries Notes Payable 1 (a) 7.59 2026 AEP Subsidiaries Notes Payable 1 (a) 8.03 2026 AGR Other Long-term Debt 500 Variable 2015 AGR Pollution Control Bonds 50 Variable 2015 AGR Pollution Control Bonds 39 Variable 2015 TCC Securitization Bonds 81 5.09 2015 TCC Securitization Bonds 76 6.25 2016 TCC Securitization Bonds 27 0.88 2017 TCC Securitization Bonds 57 5.17 2018 Total Retirements and Principal Payments $ 2,133 (a) (a) Amount includes principal payments of debt related to AEPRO that has been classified as Discontinued Operations on the condensed statement of cash flows. |
Short Term Debt | September 30, 2015 December 31, 2014 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 750 0.28 % $ 744 0.22 % Commercial Paper 32 0.44 % 602 0.59 % Total Short-term Debt $ 782 $ 1,346 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance |
Comparative Accounts Receivable Information | Three Months Ended Nine Months Ended 2015 2014 2015 2014 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.30 % 0.21 % 0.28 % 0.22 % Net Uncollectible Accounts Receivable Written Off $ 13 $ 16 $ 27 $ 32 |
Customer Accounts Receivable Managed Portfolio | September 30, 2015 December 31, 2014 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 970 $ 975 Total Principal Outstanding 750 744 Delinquent Securitized Accounts Receivable 50 44 Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable 16 13 Unbilled Receivables Related to Securitization/Sale of Accounts Receivable 277 335 |
Appalachian Power Co [Member] | |
Long-term Debt Issuances | Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. |
Retirements and Principal Payments | Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 28 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 22,524 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 20,601 Variable 2017 I&M Notes Payable 26,512 Variable 2019 I&M Notes Payable 16,265 Variable 2019 I&M Notes Payable 1,273 Variable 2016 I&M Notes Payable 882 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 838 6.00 2025 OPCo Other Long-term Debt 58 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 45,426 0.958 2018 PSO Other Long-term Debt 319 3.00 2027 SWEPCo Notes Payable 3,250 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 SWEPCo Senior Unsecured Notes 150,000 4.90 2015 |
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 46,664 $ 97,657 $ (11,689 ) $ 600,000 I&M 200,032 13,515 136,890 13,503 (137,496 ) 500,000 OPCo — 367,472 — 256,020 279,129 400,000 PSO 165,947 152,498 113,117 74,225 116,345 300,000 SWEPCo 112,481 299,932 52,596 121,845 43,073 350,000 |
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Nine Months Ended September 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % |
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 APCo 0.46 % 0.26 % 0.46 % 0.28 % I&M 0.47 % 0.27 % 0.46 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.27 % 0.46 % — % SWEPCo 0.46 % 0.28 % 0.48 % 0.27 % |
Accounts Receivable and Accrued Unbilled Revenues | September 30, December 31, Company 2015 2014 (in thousands) APCo $ 125,153 $ 159,823 I&M 139,481 137,459 OPCo 354,276 365,834 PSO 146,039 112,905 SWEPCo 176,113 148,668 |
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,952 $ 2,166 $ 5,979 $ 6,626 I&M 2,191 2,011 6,611 5,836 OPCo 8,545 7,213 23,228 21,358 PSO 1,709 1,745 4,455 4,417 SWEPCo 1,997 1,890 5,344 5,035 |
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 355,275 $ 354,406 $ 1,115,492 $ 1,137,564 I&M 401,518 372,422 1,192,137 1,132,603 OPCo 670,677 668,112 1,949,042 1,980,764 PSO 411,523 398,567 1,025,909 1,014,320 SWEPCo 468,027 466,828 1,222,294 1,278,325 |
Indiana Michigan Power Co [Member] | |
Long-term Debt Issuances | Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. |
Retirements and Principal Payments | Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 28 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 22,524 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 20,601 Variable 2017 I&M Notes Payable 26,512 Variable 2019 I&M Notes Payable 16,265 Variable 2019 I&M Notes Payable 1,273 Variable 2016 I&M Notes Payable 882 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 838 6.00 2025 OPCo Other Long-term Debt 58 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 45,426 0.958 2018 PSO Other Long-term Debt 319 3.00 2027 SWEPCo Notes Payable 3,250 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 SWEPCo Senior Unsecured Notes 150,000 4.90 2015 |
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 46,664 $ 97,657 $ (11,689 ) $ 600,000 I&M 200,032 13,515 136,890 13,503 (137,496 ) 500,000 OPCo — 367,472 — 256,020 279,129 400,000 PSO 165,947 152,498 113,117 74,225 116,345 300,000 SWEPCo 112,481 299,932 52,596 121,845 43,073 350,000 |
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Nine Months Ended September 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % |
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 APCo 0.46 % 0.26 % 0.46 % 0.28 % I&M 0.47 % 0.27 % 0.46 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.27 % 0.46 % — % SWEPCo 0.46 % 0.28 % 0.48 % 0.27 % |
Accounts Receivable and Accrued Unbilled Revenues | September 30, December 31, Company 2015 2014 (in thousands) APCo $ 125,153 $ 159,823 I&M 139,481 137,459 OPCo 354,276 365,834 PSO 146,039 112,905 SWEPCo 176,113 148,668 |
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,952 $ 2,166 $ 5,979 $ 6,626 I&M 2,191 2,011 6,611 5,836 OPCo 8,545 7,213 23,228 21,358 PSO 1,709 1,745 4,455 4,417 SWEPCo 1,997 1,890 5,344 5,035 |
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 355,275 $ 354,406 $ 1,115,492 $ 1,137,564 I&M 401,518 372,422 1,192,137 1,132,603 OPCo 670,677 668,112 1,949,042 1,980,764 PSO 411,523 398,567 1,025,909 1,014,320 SWEPCo 468,027 466,828 1,222,294 1,278,325 |
Ohio Power Co [Member] | |
Long-term Debt Issuances | Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. |
Retirements and Principal Payments | Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 28 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 22,524 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 20,601 Variable 2017 I&M Notes Payable 26,512 Variable 2019 I&M Notes Payable 16,265 Variable 2019 I&M Notes Payable 1,273 Variable 2016 I&M Notes Payable 882 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 838 6.00 2025 OPCo Other Long-term Debt 58 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 45,426 0.958 2018 PSO Other Long-term Debt 319 3.00 2027 SWEPCo Notes Payable 3,250 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 SWEPCo Senior Unsecured Notes 150,000 4.90 2015 |
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 46,664 $ 97,657 $ (11,689 ) $ 600,000 I&M 200,032 13,515 136,890 13,503 (137,496 ) 500,000 OPCo — 367,472 — 256,020 279,129 400,000 PSO 165,947 152,498 113,117 74,225 116,345 300,000 SWEPCo 112,481 299,932 52,596 121,845 43,073 350,000 |
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Nine Months Ended September 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % |
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 APCo 0.46 % 0.26 % 0.46 % 0.28 % I&M 0.47 % 0.27 % 0.46 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.27 % 0.46 % — % SWEPCo 0.46 % 0.28 % 0.48 % 0.27 % |
Accounts Receivable and Accrued Unbilled Revenues | September 30, December 31, Company 2015 2014 (in thousands) APCo $ 125,153 $ 159,823 I&M 139,481 137,459 OPCo 354,276 365,834 PSO 146,039 112,905 SWEPCo 176,113 148,668 |
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,952 $ 2,166 $ 5,979 $ 6,626 I&M 2,191 2,011 6,611 5,836 OPCo 8,545 7,213 23,228 21,358 PSO 1,709 1,745 4,455 4,417 SWEPCo 1,997 1,890 5,344 5,035 |
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 355,275 $ 354,406 $ 1,115,492 $ 1,137,564 I&M 401,518 372,422 1,192,137 1,132,603 OPCo 670,677 668,112 1,949,042 1,980,764 PSO 411,523 398,567 1,025,909 1,014,320 SWEPCo 468,027 466,828 1,222,294 1,278,325 |
Public Service Co Of Oklahoma [Member] | |
Long-term Debt Issuances | Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. |
Retirements and Principal Payments | Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 28 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 22,524 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 20,601 Variable 2017 I&M Notes Payable 26,512 Variable 2019 I&M Notes Payable 16,265 Variable 2019 I&M Notes Payable 1,273 Variable 2016 I&M Notes Payable 882 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 838 6.00 2025 OPCo Other Long-term Debt 58 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 45,426 0.958 2018 PSO Other Long-term Debt 319 3.00 2027 SWEPCo Notes Payable 3,250 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 SWEPCo Senior Unsecured Notes 150,000 4.90 2015 |
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 46,664 $ 97,657 $ (11,689 ) $ 600,000 I&M 200,032 13,515 136,890 13,503 (137,496 ) 500,000 OPCo — 367,472 — 256,020 279,129 400,000 PSO 165,947 152,498 113,117 74,225 116,345 300,000 SWEPCo 112,481 299,932 52,596 121,845 43,073 350,000 |
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Nine Months Ended September 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % |
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 APCo 0.46 % 0.26 % 0.46 % 0.28 % I&M 0.47 % 0.27 % 0.46 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.27 % 0.46 % — % SWEPCo 0.46 % 0.28 % 0.48 % 0.27 % |
Accounts Receivable and Accrued Unbilled Revenues | September 30, December 31, Company 2015 2014 (in thousands) APCo $ 125,153 $ 159,823 I&M 139,481 137,459 OPCo 354,276 365,834 PSO 146,039 112,905 SWEPCo 176,113 148,668 |
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,952 $ 2,166 $ 5,979 $ 6,626 I&M 2,191 2,011 6,611 5,836 OPCo 8,545 7,213 23,228 21,358 PSO 1,709 1,745 4,455 4,417 SWEPCo 1,997 1,890 5,344 5,035 |
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 355,275 $ 354,406 $ 1,115,492 $ 1,137,564 I&M 401,518 372,422 1,192,137 1,132,603 OPCo 670,677 668,112 1,949,042 1,980,764 PSO 411,523 398,567 1,025,909 1,014,320 SWEPCo 468,027 466,828 1,222,294 1,278,325 |
Southwestern Electric Power Co [Member] | |
Long-term Debt Issuances | Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. |
Retirements and Principal Payments | Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 28 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 22,524 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 20,601 Variable 2017 I&M Notes Payable 26,512 Variable 2019 I&M Notes Payable 16,265 Variable 2019 I&M Notes Payable 1,273 Variable 2016 I&M Notes Payable 882 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 838 6.00 2025 OPCo Other Long-term Debt 58 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 45,426 0.958 2018 PSO Other Long-term Debt 319 3.00 2027 SWEPCo Notes Payable 3,250 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 SWEPCo Senior Unsecured Notes 150,000 4.90 2015 |
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool September 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 46,664 $ 97,657 $ (11,689 ) $ 600,000 I&M 200,032 13,515 136,890 13,503 (137,496 ) 500,000 OPCo — 367,472 — 256,020 279,129 400,000 PSO 165,947 152,498 113,117 74,225 116,345 300,000 SWEPCo 112,481 299,932 52,596 121,845 43,073 350,000 |
Nonutility Money Pool Activity [Text Block] | Maximum Maximum Average Average Loans Borrowings Loans Borrowings Loans to the Nonutility from the Nonutility to the Nonutility from the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool Money Pool Money Pool September 30, 2015 (in thousands) $ — $ 1,948 $ — $ 1,945 $ 1,946 |
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Nine Months Ended September 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % |
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | Average Interest Rate Average Interest Rate for Funds Borrowed for Funds Loaned from the Utility Money Pool for to the Utility Money Pool for Nine Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 APCo 0.46 % 0.26 % 0.46 % 0.28 % I&M 0.47 % 0.27 % 0.46 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.27 % 0.46 % — % SWEPCo 0.46 % 0.28 % 0.48 % 0.27 % |
Accounts Receivable and Accrued Unbilled Revenues | September 30, December 31, Company 2015 2014 (in thousands) APCo $ 125,153 $ 159,823 I&M 139,481 137,459 OPCo 354,276 365,834 PSO 146,039 112,905 SWEPCo 176,113 148,668 |
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,952 $ 2,166 $ 5,979 $ 6,626 I&M 2,191 2,011 6,611 5,836 OPCo 8,545 7,213 23,228 21,358 PSO 1,709 1,745 4,455 4,417 SWEPCo 1,997 1,890 5,344 5,035 |
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 355,275 $ 354,406 $ 1,115,492 $ 1,137,564 I&M 401,518 372,422 1,192,137 1,132,603 OPCo 670,677 668,112 1,949,042 1,980,764 PSO 411,523 398,567 1,025,909 1,014,320 SWEPCo 468,027 466,828 1,222,294 1,278,325 |
Maximum Minimum Average Interest Rates for Funds Borrowed from Loaned to Nonutility Money Pool [Text Block] | Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Nine Months Borrowed from Borrowed from Loaned to Loaned to Borrowed from Loaned to Ended the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility the Nonutility September 30, Money Pool Money Pool Money Pool Money Pool Money Pool Money Pool 2015 — % — % 0.59 % 0.39 % — % 0.47 % 2014 — % — % 0.33 % — % — % 0.28 % |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Consolidated Assets and Liabilities of Variable Interest Entities | AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES September 30, 2015 (in millions) SWEPCo Sabine I&M DCC Fuel AEP Credit TCC Transition Funding OPCo Ohio Phase-in- Recovery Funding APCo Appalachian Consumer Rate Relief Funding Protected Cell of EIS Transource Energy ASSETS Current Assets $ 61 $ 104 $ 977 $ 197 $ 20 $ 11 $ 163 $ 12 Net Property, Plant and Equipment 144 193 — — — — — 184 Other Noncurrent Assets 60 101 1 1,454 (a) 175 (b) 341 (c) 3 5 Total Assets $ 265 $ 398 $ 978 $ 1,651 $ 195 $ 352 $ 166 $ 201 LIABILITIES AND EQUITY Current Liabilities $ 40 $ 98 $ 875 $ 283 $ 47 $ 25 $ 49 $ 47 Noncurrent Liabilities 225 300 1 1,350 147 325 76 80 Equity — — 102 18 1 2 41 74 Total Liabilities and Equity $ 265 $ 398 $ 978 $ 1,651 $ 195 $ 352 $ 166 $ 201 (a) Includes an intercompany item eliminated in consolidation of $70 million . (b) Includes an intercompany item eliminated in consolidation of $81 million . (c) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 (in millions) SWEPCo Sabine I&M DCC Fuel AEP Credit TCC Transition Funding OPCo Ohio Phase-in- Recovery Funding APCo Appalachian Consumer Rate Relief Funding Protected Cell of EIS Transource Energy ASSETS Current Assets $ 68 $ 97 $ 980 $ 239 $ 33 $ 18 $ 149 $ 2 Net Property, Plant and Equipment 145 158 — — — — — 98 Other Noncurrent Assets 52 80 — 1,654 (a) 210 (b) 358 (c) 2 4 Total Assets $ 265 $ 335 $ 980 $ 1,893 $ 243 $ 376 $ 151 $ 104 LIABILITIES AND EQUITY Current Liabilities $ 36 $ 86 $ 894 $ 322 $ 47 $ 27 $ 44 $ 21 Noncurrent Liabilities 228 249 — 1,553 195 347 62 55 Equity 1 — 86 18 1 2 45 28 Total Liabilities and Equity $ 265 $ 335 $ 980 $ 1,893 $ 243 $ 376 $ 151 $ 104 (a) Includes an intercompany item eliminated in consolidation of $75 million . (b) Includes an intercompany item eliminated in consolidation of $97 million . (c) Includes an intercompany item eliminated in consolidation of $4 million . |
Appalachian Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | |
Billings from Significant Variable Interest | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 63,687 $ 50,143 $ 164,657 $ 154,239 I&M 37,506 30,613 102,141 92,686 OPCo 48,471 41,212 128,608 120,696 PSO 29,851 24,317 77,817 71,646 SWEPCo 39,150 32,787 102,564 98,528 |
Appalachian Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |
Carrying Amount and Classification of Variable Interest in Accounts Payable | September 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 23,783 $ 23,783 $ 30,692 $ 30,692 I&M 13,676 13,676 22,480 22,480 OPCo 18,770 18,770 24,695 24,695 PSO 10,713 10,713 15,338 15,338 SWEPCo 14,295 14,295 20,772 20,772 |
Indiana Michigan Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | |
Billings from Significant Variable Interest | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 63,687 $ 50,143 $ 164,657 $ 154,239 I&M 37,506 30,613 102,141 92,686 OPCo 48,471 41,212 128,608 120,696 PSO 29,851 24,317 77,817 71,646 SWEPCo 39,150 32,787 102,564 98,528 |
Indiana Michigan Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |
Carrying Amount and Classification of Variable Interest in Accounts Payable | September 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 23,783 $ 23,783 $ 30,692 $ 30,692 I&M 13,676 13,676 22,480 22,480 OPCo 18,770 18,770 24,695 24,695 PSO 10,713 10,713 15,338 15,338 SWEPCo 14,295 14,295 20,772 20,772 |
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | |
Consolidated Assets and Liabilities of Variable Interest Entities | INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) DCC Fuel ASSETS 2015 2014 Current Assets $ 104,273 $ 97,361 Net Property, Plant and Equipment 193,447 158,121 Other Noncurrent Assets 99,811 79,705 Total Assets $ 397,531 $ 335,187 LIABILITIES AND EQUITY Current Liabilities $ 98,173 $ 86,026 Noncurrent Liabilities 299,358 249,161 Total Liabilities and Equity $ 397,531 $ 335,187 |
Ohio Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | |
Billings from Significant Variable Interest | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 63,687 $ 50,143 $ 164,657 $ 154,239 I&M 37,506 30,613 102,141 92,686 OPCo 48,471 41,212 128,608 120,696 PSO 29,851 24,317 77,817 71,646 SWEPCo 39,150 32,787 102,564 98,528 |
Ohio Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |
Carrying Amount and Classification of Variable Interest in Accounts Payable | September 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 23,783 $ 23,783 $ 30,692 $ 30,692 I&M 13,676 13,676 22,480 22,480 OPCo 18,770 18,770 24,695 24,695 PSO 10,713 10,713 15,338 15,338 SWEPCo 14,295 14,295 20,772 20,772 |
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | |
Consolidated Assets and Liabilities of Variable Interest Entities | OHIO POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Ohio Phase-In Recovery Funding ASSETS 2015 2014 Current Assets $ 20,236 $ 32,676 Other Noncurrent Assets (a) 175,189 209,922 Total Assets $ 195,425 $ 242,598 LIABILITIES AND EQUITY Current Liabilities $ 46,592 $ 47,099 Noncurrent Liabilities 147,496 194,162 Equity 1,337 1,337 Total Liabilities and Equity $ 195,425 $ 242,598 (a) Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $81 million and $97 million , respectively. |
Public Service Co Of Oklahoma [Member] | Billings from American Electric Power Service Corporation [Member] | |
Billings from Significant Variable Interest | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 63,687 $ 50,143 $ 164,657 $ 154,239 I&M 37,506 30,613 102,141 92,686 OPCo 48,471 41,212 128,608 120,696 PSO 29,851 24,317 77,817 71,646 SWEPCo 39,150 32,787 102,564 98,528 |
Public Service Co Of Oklahoma [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |
Carrying Amount and Classification of Variable Interest in Accounts Payable | September 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 23,783 $ 23,783 $ 30,692 $ 30,692 I&M 13,676 13,676 22,480 22,480 OPCo 18,770 18,770 24,695 24,695 PSO 10,713 10,713 15,338 15,338 SWEPCo 14,295 14,295 20,772 20,772 |
Southwestern Electric Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | |
Billings from Significant Variable Interest | Three Months Ended September 30, Nine Months Ended September 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 63,687 $ 50,143 $ 164,657 $ 154,239 I&M 37,506 30,613 102,141 92,686 OPCo 48,471 41,212 128,608 120,696 PSO 29,851 24,317 77,817 71,646 SWEPCo 39,150 32,787 102,564 98,528 |
Southwestern Electric Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |
Carrying Amount and Classification of Variable Interest in Accounts Payable | September 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 23,783 $ 23,783 $ 30,692 $ 30,692 I&M 13,676 13,676 22,480 22,480 OPCo 18,770 18,770 24,695 24,695 PSO 10,713 10,713 15,338 15,338 SWEPCo 14,295 14,295 20,772 20,772 |
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | |
Consolidated Assets and Liabilities of Variable Interest Entities | SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Sabine ASSETS 2015 2014 Current Assets $ 61,025 $ 67,981 Net Property, Plant and Equipment 143,815 145,491 Other Noncurrent Assets 60,160 51,578 Total Assets $ 265,000 $ 265,050 LIABILITIES AND EQUITY Current Liabilities $ 40,311 $ 36,286 Noncurrent Liabilities 224,371 228,349 Equity 318 415 Total Liabilities and Equity $ 265,000 $ 265,050 |
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | |
Companys Investment In Joint Venture | September 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) Capital Contribution from SWEPCo $ 7,643 $ 7,643 $ 7,643 $ 7,643 Retained Earnings 5,950 5,950 3,819 3,819 SWEPCo's Guarantee of Debt — 95,180 (a) — 104,334 (a) Total Investment in DHLC $ 13,593 $ 108,773 $ 11,462 $ 115,796 (a) Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $40 million and $56 million in 2015 and 2014 , respectively. |
PATH West Virginia Transmission Co, LLC [Member] | |
Companys Investment In Joint Venture | September 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from AEP $ 19 $ 19 $ 19 $ 19 Retained Earnings 2 2 2 2 Total Investment in PATH-WV $ 21 $ 21 $ 21 $ 21 |
Appalachian Consumer Rate Relief Funding [Member] | Appalachian Power Co [Member] | |
Consolidated Assets and Liabilities of Variable Interest Entities | APPALACHIAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES September 30, 2015 and December 31, 2014 (in thousands) Appalachian Consumer Rate Relief Funding ASSETS 2015 2014 Current Assets $ 10,914 $ 18,099 Other Noncurrent Assets (a) 341,127 358,264 Total Assets $ 352,041 $ 376,363 LIABILITIES AND EQUITY Current Liabilities $ 24,617 $ 26,809 Noncurrent Liabilities 325,534 347,652 Equity 1,890 1,902 Total Liabilities and Equity $ 352,041 $ 376,363 (a) Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $4 million and $4 million , respectively. |
Property, Plant and Equipment42
Property, Plant and Equipment Property, Plant and Equipment (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Asset Retirement Obligation (ARO) | Carrying Amount of ARO (in millions) ARO as of December 31, 2014 $ 2,019 Accretion Expense 76 Liabilities Incurred 48 Liabilities Settled (a) (126 ) Revisions in Cash Flow Estimates (b) 30 ARO as of September 30, 2015 $ 2,047 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the "Muskingum River Plant" section of Note 6 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. |
Appalachian Power Co [Member] | |
Asset Retirement Obligation (ARO) | ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates September 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 6,239 $ — $ (23,471 ) $ 16,977 $ 148,122 I&M (a)(b)(d) 1,342,549 47,918 — (3,977 ) 5,638 1,392,128 OPCo (d)(e) 1,361 62 — (8 ) — 1,415 PSO (a)(d) 38,020 1,923 5,336 (125 ) 1,916 47,070 SWEPCo (a)(c)(d) 94,394 4,299 12,191 (3,358 ) 6,349 113,875 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule. |
Indiana Michigan Power Co [Member] | |
Asset Retirement Obligation (ARO) | ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates September 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 6,239 $ — $ (23,471 ) $ 16,977 $ 148,122 I&M (a)(b)(d) 1,342,549 47,918 — (3,977 ) 5,638 1,392,128 OPCo (d)(e) 1,361 62 — (8 ) — 1,415 PSO (a)(d) 38,020 1,923 5,336 (125 ) 1,916 47,070 SWEPCo (a)(c)(d) 94,394 4,299 12,191 (3,358 ) 6,349 113,875 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule. |
Ohio Power Co [Member] | |
Asset Retirement Obligation (ARO) | ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates September 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 6,239 $ — $ (23,471 ) $ 16,977 $ 148,122 I&M (a)(b)(d) 1,342,549 47,918 — (3,977 ) 5,638 1,392,128 OPCo (d)(e) 1,361 62 — (8 ) — 1,415 PSO (a)(d) 38,020 1,923 5,336 (125 ) 1,916 47,070 SWEPCo (a)(c)(d) 94,394 4,299 12,191 (3,358 ) 6,349 113,875 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule. |
Public Service Co Of Oklahoma [Member] | |
Asset Retirement Obligation (ARO) | ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates September 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 6,239 $ — $ (23,471 ) $ 16,977 $ 148,122 I&M (a)(b)(d) 1,342,549 47,918 — (3,977 ) 5,638 1,392,128 OPCo (d)(e) 1,361 62 — (8 ) — 1,415 PSO (a)(d) 38,020 1,923 5,336 (125 ) 1,916 47,070 SWEPCo (a)(c)(d) 94,394 4,299 12,191 (3,358 ) 6,349 113,875 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule. |
Southwestern Electric Power Co [Member] | |
Asset Retirement Obligation (ARO) | ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates September 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 6,239 $ — $ (23,471 ) $ 16,977 $ 148,122 I&M (a)(b)(d) 1,342,549 47,918 — (3,977 ) 5,638 1,392,128 OPCo (d)(e) 1,361 62 — (8 ) — 1,415 PSO (a)(d) 38,020 1,923 5,336 (125 ) 1,916 47,070 SWEPCo (a)(c)(d) 94,394 4,299 12,191 (3,358 ) 6,349 113,875 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule. |
Disposition Plant Severance (Ta
Disposition Plant Severance (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Disposition Plant Severance [Member] | |
Remaining Accrual | Disposition Plant Severance Activity (in millions) Balance as of December 31, 2014 $ 29 Incurred 3 Settled (21 ) Adjustments — Balance as of September 30, 2015 $ 11 |
Appalachian Power Co [Member] | |
Total Cost Incurred | Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 |
Remaining Accrual | Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments September 30, 2015 (in thousands) APCo $ 9,304 $ (6 ) $ 849 $ (6,385 ) (a) $ (119 ) $ 3,643 I&M 8,023 (2 ) 351 (5,110 ) — 3,262 PSO 134 (3 ) 415 (121 ) — 425 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. |
Indiana Michigan Power Co [Member] | |
Total Cost Incurred | Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 |
Remaining Accrual | Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments September 30, 2015 (in thousands) APCo $ 9,304 $ (6 ) $ 849 $ (6,385 ) (a) $ (119 ) $ 3,643 I&M 8,023 (2 ) 351 (5,110 ) — 3,262 PSO 134 (3 ) 415 (121 ) — 425 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. |
Ohio Power Co [Member] | |
Total Cost Incurred | Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 |
Remaining Accrual | Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments September 30, 2015 (in thousands) APCo $ 9,304 $ (6 ) $ 849 $ (6,385 ) (a) $ (119 ) $ 3,643 I&M 8,023 (2 ) 351 (5,110 ) — 3,262 PSO 134 (3 ) 415 (121 ) — 425 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. |
Public Service Co Of Oklahoma [Member] | |
Total Cost Incurred | Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 |
Remaining Accrual | Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments September 30, 2015 (in thousands) APCo $ 9,304 $ (6 ) $ 849 $ (6,385 ) (a) $ (119 ) $ 3,643 I&M 8,023 (2 ) 351 (5,110 ) — 3,262 PSO 134 (3 ) 415 (121 ) — 425 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. |
Southwestern Electric Power Co [Member] | |
Total Cost Incurred | Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 |
Remaining Accrual | Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments September 30, 2015 (in thousands) APCo $ 9,304 $ (6 ) $ 849 $ (6,385 ) (a) $ (119 ) $ 3,643 I&M 8,023 (2 ) 351 (5,110 ) — 3,262 PSO 134 (3 ) 415 (121 ) — 425 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. |
Significant Accounting Matter44
Significant Accounting Matters (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Income from Continuing Operations | $ 512,000 | $ 483,000 | $ 1,564,000 | $ 1,430,000 |
Net Income (Loss) Attributable to Noncontrolling Interests | 1,000 | 1,000 | 4,000 | 3,000 |
Income (Loss) from Continuing Operations Attributable to Parent | $ 511,000 | $ 482,000 | $ 1,560,000 | $ 1,427,000 |
Weighted Average Number of Shares Outstanding | 490,648,929 | 488,912,892 | 490,155,315 | 488,361,017 |
Basic and Diluted EPS Calculations | ||||
Income (Loss) from Continuing Operations, Per Basic Share | $ 1.04 | $ 0.99 | $ 3.18 | $ 2.92 |
Weighted Average Dilutive Effect of: | ||||
Weighted Average Number of Shares Outstanding | 490,800,335 | 488,970,647 | 490,411,020 | 488,597,178 |
Income (Loss) from Continuing Operations, Per Diluted Share | $ 1.04 | $ 0.99 | $ 3.18 | $ 2.92 |
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Antidilutive Shares Outstanding | 0 | 0 | ||
Cash Paid (Received) for: | ||||
Cash Paid for Interest, Net of Capitalized Amounts | $ 639,000 | $ 649,000 | ||
Net Cash Paid (Received) for Income Taxes | 116,000 | 109,000 | ||
Noncash Investing and Financing Activities: | ||||
Noncash Acquisitions Under Capital Leases | 97,000 | 80,000 | ||
Construction Expenditures Included in Current Liabilities as of September 30, | 579,000 | 515,000 | ||
Construction Expenditures Included in Noncurrent Liabilities as of September 30, | 66,000 | 0 | ||
Acquisition Of Nuclear Fuel Included In Current Liabilities | 31,000 | 0 | ||
Appalachian Power Co [Member] | ||||
Cash Paid (Received) for: | ||||
Cash Paid for Interest, Net of Capitalized Amounts | 128,435 | 136,919 | ||
Net Cash Paid (Received) for Income Taxes | 33,712 | 22,148 | ||
Noncash Investing and Financing Activities: | ||||
Noncash Acquisitions Under Capital Leases | 2,257 | 3,451 | ||
Construction Expenditures Included in Current Liabilities as of September 30, | 80,990 | 54,463 | ||
Indiana Michigan Power Co [Member] | ||||
Cash Paid (Received) for: | ||||
Cash Paid for Interest, Net of Capitalized Amounts | 77,450 | 75,789 | ||
Net Cash Paid (Received) for Income Taxes | 17,203 | (1,475) | ||
Noncash Investing and Financing Activities: | ||||
Noncash Acquisitions Under Capital Leases | 1,990 | 5,015 | ||
Construction Expenditures Included in Current Liabilities as of September 30, | 51,582 | 69,241 | ||
Acquisition Of Nuclear Fuel Included In Current Liabilities | 31,140 | 11 | ||
Ohio Power Co [Member] | ||||
Cash Paid (Received) for: | ||||
Cash Paid for Interest, Net of Capitalized Amounts | 79,019 | 90,188 | ||
Net Cash Paid (Received) for Income Taxes | 24,060 | 15,523 | ||
Noncash Investing and Financing Activities: | ||||
Noncash Acquisitions Under Capital Leases | 2,115 | 4,505 | ||
Construction Expenditures Included in Current Liabilities as of September 30, | 30,209 | 45,691 | ||
Public Service Co Of Oklahoma [Member] | ||||
Cash Paid (Received) for: | ||||
Cash Paid for Interest, Net of Capitalized Amounts | 40,562 | 37,458 | ||
Net Cash Paid (Received) for Income Taxes | 12,772 | (416) | ||
Noncash Investing and Financing Activities: | ||||
Noncash Acquisitions Under Capital Leases | 1,546 | 2,098 | ||
Construction Expenditures Included in Current Liabilities as of September 30, | 37,328 | 33,527 | ||
Southwestern Electric Power Co [Member] | ||||
Net Income (Loss) Attributable to Noncontrolling Interests | $ 1,013 | $ 1,109 | 3,002 | 3,337 |
Cash Paid (Received) for: | ||||
Cash Paid for Interest, Net of Capitalized Amounts | 106,078 | 113,137 | ||
Net Cash Paid (Received) for Income Taxes | 12,320 | (13,820) | ||
Noncash Investing and Financing Activities: | ||||
Noncash Acquisitions Under Capital Leases | 1,493 | 3,923 | ||
Construction Expenditures Included in Current Liabilities as of September 30, | $ 85,268 | $ 88,291 | ||
Restricted Stock Units [Member] | ||||
Weighted Average Dilutive Effect of: | ||||
Weighted Average Dilutive Effect of Shares | 200,000 | 100,000 | 200,000 | 200,000 |
Dilutive Securities, Effect on Basic Earnings Per Share | $ 0 | $ 0 | $ 0 | $ 0 |
Comprehensive Income (Details)
Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | $ (102,000) | $ (104,000) | $ (103,000) | $ (115,000) | |
Change in Fair Value Recognized in AOCI | (4,000) | 3,000 | (3,000) | (7,000) | |
Amounts Reclassified from AOCI | (3,000) | (4,000) | (8,000) | 17,000 | |
Net Current Period Other Comprehensive Income | (7,000) | (1,000) | (11,000) | 10,000 | |
Pension and OPEB Adjustment Related to Mitchell Plant | 5,000 | ||||
Ending Balance in AOCI | (109,000) | (105,000) | (109,000) | (105,000) | |
Commodity: | |||||
Generation & Marketing Revenues | 30,000 | 28,000 | 90,000 | 22,000 | |
Purchased Electricity for Resale | 731,000 | 449,000 | 2,050,000 | 1,560,000 | |
Other Operation Expense | 691,000 | 685,000 | 1,955,000 | 1,985,000 | |
Maintenance Expense | 312,000 | 313,000 | 923,000 | 929,000 | |
Interest Rate and Foreign Currency: | |||||
Depreciation and Amortization Expense | 535,000 | 499,000 | 1,528,000 | 1,418,000 | |
Interest Expense | 221,000 | 217,000 | 659,000 | 650,000 | |
Income Tax (Expense) Credit | (275,000) | (264,000) | (827,000) | (783,000) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (3,000) | (4,000) | (8,000) | 17,000 | |
Gains and Losses on Available-for-Sale Securities | |||||
Interest Expense | 221,000 | 217,000 | 659,000 | 650,000 | |
Income Tax (Expense) Credit | (275,000) | (264,000) | (827,000) | (783,000) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (3,000) | (4,000) | (8,000) | 17,000 | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | (275,000) | (264,000) | (827,000) | (783,000) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (3,000) | (4,000) | (8,000) | 17,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (3,000) | (4,000) | (8,000) | 17,000 | |
Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Amounts Reclassified from AOCI | (3,000) | (5,000) | (9,000) | 14,000 | |
Commodity: | |||||
Subtotal - Commodity | (5,000) | (7,000) | (15,000) | 23,000 | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | (5,000) | (7,000) | (15,000) | 23,000 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (5,000) | (7,000) | (15,000) | 23,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (3,000) | (5,000) | (9,000) | 14,000 | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (5,000) | (7,000) | (15,000) | 23,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (3,000) | (5,000) | (9,000) | 14,000 | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (5,000) | (7,000) | (15,000) | 23,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (3,000) | (5,000) | (9,000) | 14,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (3,000) | (5,000) | (9,000) | 14,000 | |
Securities Available for Sale [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 8,000 | 8,000 | 8,000 | 7,000 | |
Change in Fair Value Recognized in AOCI | (1,000) | 0 | (1,000) | 1,000 | |
Amounts Reclassified from AOCI | 0 | 0 | 0 | 0 | |
Net Current Period Other Comprehensive Income | (1,000) | 0 | (1,000) | 1,000 | |
Pension and OPEB Adjustment Related to Mitchell Plant | 0 | ||||
Ending Balance in AOCI | 7,000 | 8,000 | 7,000 | 8,000 | |
Interest Rate and Foreign Currency: | |||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | 0 | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | 0 | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | 0 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | 0 | |
Pension and OPEB [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | (87,000) | (97,000) | (93,000) | (99,000) | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | 0 | 1,000 | 1,000 | 3,000 | |
Net Current Period Other Comprehensive Income | 0 | 1,000 | 1,000 | 3,000 | |
Pension and OPEB Adjustment Related to Mitchell Plant | 5,000 | ||||
Ending Balance in AOCI | (87,000) | (96,000) | (87,000) | (96,000) | |
Commodity: | |||||
Subtotal - Commodity | 0 | 2,000 | 1,000 | 6,000 | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | 0 | 2,000 | 1,000 | 6,000 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 2,000 | 1,000 | 6,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 1,000 | 1,000 | 3,000 | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 2,000 | 1,000 | 6,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 1,000 | 1,000 | 3,000 | |
Amortization of Pension and OPEB | |||||
Prior Service Cost (Credit) | (5,000) | (5,000) | (15,000) | (15,000) | |
Actuarial (Gains)/Losses | 5,000 | 7,000 | 16,000 | 21,000 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 2,000 | 1,000 | 6,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 1,000 | 1,000 | 3,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 1,000 | 1,000 | 3,000 | |
Commodity [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | (5,000) | 6,000 | 1,000 | 0 | |
Change in Fair Value Recognized in AOCI | (3,000) | 3,000 | (2,000) | (8,000) | |
Amounts Reclassified from AOCI | (3,000) | (6,000) | (10,000) | 11,000 | |
Net Current Period Other Comprehensive Income | (6,000) | (3,000) | (12,000) | 3,000 | |
Pension and OPEB Adjustment Related to Mitchell Plant | 0 | ||||
Ending Balance in AOCI | (11,000) | 3,000 | (11,000) | 3,000 | |
Commodity: | |||||
Subtotal - Commodity | (5,000) | (9,000) | (16,000) | 17,000 | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | (5,000) | (9,000) | (16,000) | 17,000 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (5,000) | (9,000) | (16,000) | 17,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (3,000) | (6,000) | (10,000) | 11,000 | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (5,000) | (9,000) | (16,000) | 17,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (3,000) | (6,000) | (10,000) | 11,000 | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (5,000) | (9,000) | (16,000) | 17,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (3,000) | (6,000) | (10,000) | 11,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (3,000) | (6,000) | (10,000) | 11,000 | |
Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | (18,000) | (21,000) | (19,000) | (23,000) | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | 0 | 1,000 | 1,000 | 3,000 | |
Net Current Period Other Comprehensive Income | 0 | 1,000 | 1,000 | 3,000 | |
Pension and OPEB Adjustment Related to Mitchell Plant | 0 | ||||
Ending Balance in AOCI | (18,000) | (20,000) | (18,000) | (20,000) | |
Commodity: | |||||
Subtotal - Commodity | 0 | 2,000 | 1,000 | 6,000 | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | 0 | 2,000 | 1,000 | 6,000 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 2,000 | 1,000 | 6,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 1,000 | 1,000 | 3,000 | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 2,000 | 1,000 | 6,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 1,000 | 1,000 | 3,000 | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 2,000 | 1,000 | 6,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 1,000 | 1,000 | 3,000 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 1,000 | 1,000 | 3,000 | |
Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Income Tax (Expense) Credit | (2,000) | (2,000) | (6,000) | 9,000 | |
Gains and Losses on Available-for-Sale Securities | |||||
Income Tax (Expense) Credit | (2,000) | (2,000) | (6,000) | 9,000 | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | (2,000) | (2,000) | (6,000) | 9,000 | |
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Income Tax (Expense) Credit | 0 | 1,000 | 0 | 3,000 | |
Gains and Losses on Available-for-Sale Securities | |||||
Income Tax (Expense) Credit | 0 | 1,000 | 0 | 3,000 | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | 0 | 1,000 | 0 | 3,000 | |
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | |||||
Commodity: | |||||
Generation & Marketing Revenues | (19,000) | 0 | (36,000) | 0 | |
Purchased Electricity for Resale | 14,000 | (9,000) | 20,000 | 20,000 | |
Regulatory Assets/(Liabilities), Net | [1] | 0 | (3,000) | ||
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Interest Expense | 0 | 2,000 | 1,000 | 6,000 | |
Gains and Losses on Available-for-Sale Securities | |||||
Interest Expense | 0 | 2,000 | 1,000 | 6,000 | |
Appalachian Power Co [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 4,247 | 2,697 | 5,032 | 2,951 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 1,686 | |
Amounts Reclassified from AOCI | (680) | (163) | (1,465) | (2,103) | |
Net Current Period Other Comprehensive Income | (680) | (163) | (1,465) | (417) | |
Ending Balance in AOCI | 3,567 | 2,534 | 3,567 | 2,534 | |
Commodity: | |||||
Generation & Marketing Revenues | 2,857 | 1,970 | 7,870 | 6,537 | |
Purchased Electricity for Resale | 80,452 | 85,656 | 258,836 | 340,680 | |
Other Operation Expense | 101,841 | 103,835 | 311,631 | 297,269 | |
Maintenance Expense | 70,459 | 64,333 | 179,793 | 193,907 | |
Interest Rate and Foreign Currency: | |||||
Depreciation and Amortization Expense | 96,295 | 99,889 | 292,735 | 300,125 | |
Interest Expense | 46,625 | 52,738 | 145,600 | 157,540 | |
Income Tax (Expense) Credit | (40,507) | (31,408) | (168,368) | (121,233) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (680) | (163) | (1,465) | (2,103) | |
Gains and Losses on Available-for-Sale Securities | |||||
Interest Expense | 46,625 | 52,738 | 145,600 | 157,540 | |
Income Tax (Expense) Credit | (40,507) | (31,408) | (168,368) | (121,233) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (680) | (163) | (1,465) | (2,103) | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | (40,507) | (31,408) | (168,368) | (121,233) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (680) | (163) | (1,465) | (2,103) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (680) | (163) | (1,465) | (2,103) | |
Appalachian Power Co [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Amounts Reclassified from AOCI | (222) | 170 | (91) | (1,104) | |
Commodity: | |||||
Subtotal - Commodity | (342) | 262 | (140) | (1,696) | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | (342) | 262 | (140) | (1,696) | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (342) | 262 | (140) | (1,696) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (222) | 170 | (91) | (1,104) | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (342) | 262 | (140) | (1,696) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (222) | 170 | (91) | (1,104) | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (342) | 262 | (140) | (1,696) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (222) | 170 | (91) | (1,104) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (222) | 170 | (91) | (1,104) | |
Appalachian Power Co [Member] | Pension and OPEB [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 220 | (899) | 1,136 | (233) | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | (458) | (333) | (1,374) | (999) | |
Net Current Period Other Comprehensive Income | (458) | (333) | (1,374) | (999) | |
Ending Balance in AOCI | (238) | (1,232) | (238) | (1,232) | |
Commodity: | |||||
Subtotal - Commodity | (705) | (512) | (2,114) | (1,537) | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | (705) | (512) | (2,114) | (1,537) | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (705) | (512) | (2,114) | (1,537) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (458) | (333) | (1,374) | (999) | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (705) | (512) | (2,114) | (1,537) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (458) | (333) | (1,374) | (999) | |
Amortization of Pension and OPEB | |||||
Prior Service Cost (Credit) | (1,282) | (1,281) | (3,847) | (3,846) | |
Actuarial (Gains)/Losses | 577 | 769 | 1,733 | 2,309 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (705) | (512) | (2,114) | (1,537) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (458) | (333) | (1,374) | (999) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (458) | (333) | (1,374) | (999) | |
Appalachian Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 0 | 0 | 0 | 94 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 1,686 | |
Amounts Reclassified from AOCI | 0 | 0 | 0 | (1,780) | |
Net Current Period Other Comprehensive Income | 0 | 0 | 0 | (94) | |
Ending Balance in AOCI | 0 | 0 | 0 | 0 | |
Commodity: | |||||
Subtotal - Commodity | 0 | 0 | 0 | (2,738) | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | 0 | 0 | 0 | (2,738) | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (2,738) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (1,780) | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (2,738) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (1,780) | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (2,738) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (1,780) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (1,780) | |
Appalachian Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 4,027 | 3,596 | 3,896 | 3,090 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | (222) | 170 | (91) | 676 | |
Net Current Period Other Comprehensive Income | (222) | 170 | (91) | 676 | |
Ending Balance in AOCI | 3,805 | 3,766 | 3,805 | 3,766 | |
Commodity: | |||||
Subtotal - Commodity | (342) | 262 | (140) | 1,042 | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | (342) | 262 | (140) | 1,042 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (342) | 262 | (140) | 1,042 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (222) | 170 | (91) | 676 | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (342) | 262 | (140) | 1,042 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (222) | 170 | (91) | 676 | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (342) | 262 | (140) | 1,042 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (222) | 170 | (91) | 676 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (222) | 170 | (91) | 676 | |
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Income Tax (Expense) Credit | (120) | 92 | (49) | (592) | |
Gains and Losses on Available-for-Sale Securities | |||||
Income Tax (Expense) Credit | (120) | 92 | (49) | (592) | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | (120) | 92 | (49) | (592) | |
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Income Tax (Expense) Credit | (247) | (179) | (740) | (538) | |
Gains and Losses on Available-for-Sale Securities | |||||
Income Tax (Expense) Credit | (247) | (179) | (740) | (538) | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | (247) | (179) | (740) | (538) | |
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | |||||
Commodity: | |||||
Purchased Electricity for Resale | 0 | 0 | 0 | (526) | |
Other Operation Expense | 0 | (10) | |||
Maintenance Expense | 0 | (20) | |||
Property, Plant and Equipment | 0 | (17) | |||
Regulatory Assets/(Liabilities), Net | [1] | 0 | 0 | 0 | (2,165) |
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Interest Expense | (342) | 262 | (140) | 1,042 | |
Gains and Losses on Available-for-Sale Securities | |||||
Interest Expense | (342) | 262 | (140) | 1,042 | |
Indiana Michigan Power Co [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | (13,803) | (14,648) | (14,360) | (15,509) | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 1,130 | |
Amounts Reclassified from AOCI | 278 | 452 | 835 | 183 | |
Net Current Period Other Comprehensive Income | 278 | 452 | 835 | 1,313 | |
Ending Balance in AOCI | (13,525) | (14,196) | (13,525) | (14,196) | |
Commodity: | |||||
Generation & Marketing Revenues | 786 | 749 | 2,626 | 1,298 | |
Purchased Electricity for Resale | 41,544 | 20,019 | 147,711 | 52,467 | |
Other Operation Expense | 141,054 | 144,331 | 407,320 | 431,953 | |
Maintenance Expense | 53,727 | 59,043 | 160,907 | 161,854 | |
Interest Rate and Foreign Currency: | |||||
Depreciation and Amortization Expense | 49,215 | 50,585 | 150,162 | 150,062 | |
Interest Expense | 23,144 | 22,617 | 68,889 | 71,955 | |
Income Tax (Expense) Credit | (27,691) | (20,654) | (86,725) | (71,596) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 278 | 452 | 835 | 183 | |
Gains and Losses on Available-for-Sale Securities | |||||
Interest Expense | 23,144 | 22,617 | 68,889 | 71,955 | |
Income Tax (Expense) Credit | (27,691) | (20,654) | (86,725) | (71,596) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 278 | 452 | 835 | 183 | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | (27,691) | (20,654) | (86,725) | (71,596) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 278 | 452 | 835 | 183 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 278 | 452 | 835 | 183 | |
Indiana Michigan Power Co [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Amounts Reclassified from AOCI | 267 | 410 | 802 | 55 | |
Commodity: | |||||
Subtotal - Commodity | 412 | 631 | 1,234 | 84 | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | 412 | 631 | 1,234 | 84 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 412 | 631 | 1,234 | 84 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 267 | 410 | 802 | 55 | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 412 | 631 | 1,234 | 84 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 267 | 410 | 802 | 55 | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 412 | 631 | 1,234 | 84 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 267 | 410 | 802 | 55 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 267 | 410 | 802 | 55 | |
Indiana Michigan Power Co [Member] | Pension and OPEB [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 68 | 507 | 46 | 421 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | 11 | 42 | 33 | 128 | |
Net Current Period Other Comprehensive Income | 11 | 42 | 33 | 128 | |
Ending Balance in AOCI | 79 | 549 | 79 | 549 | |
Commodity: | |||||
Subtotal - Commodity | 17 | 64 | 51 | 194 | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | 17 | 64 | 51 | 194 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 17 | 64 | 51 | 194 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 11 | 42 | 33 | 128 | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 17 | 64 | 51 | 194 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 11 | 42 | 33 | 128 | |
Amortization of Pension and OPEB | |||||
Prior Service Cost (Credit) | (198) | (200) | (596) | (597) | |
Actuarial (Gains)/Losses | 215 | 264 | 647 | 791 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 17 | 64 | 51 | 194 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 11 | 42 | 33 | 128 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 11 | 42 | 33 | 128 | |
Indiana Michigan Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 0 | 0 | 0 | 46 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 1,130 | |
Amounts Reclassified from AOCI | 0 | 0 | 0 | (1,176) | |
Net Current Period Other Comprehensive Income | 0 | 0 | 0 | (46) | |
Ending Balance in AOCI | 0 | 0 | 0 | 0 | |
Commodity: | |||||
Subtotal - Commodity | 0 | 0 | 0 | (1,809) | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | 0 | 0 | 0 | (1,809) | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (1,809) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (1,176) | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (1,809) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (1,176) | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (1,809) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (1,176) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (1,176) | |
Indiana Michigan Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | (13,871) | (15,155) | (14,406) | (15,976) | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | 267 | 410 | 802 | 1,231 | |
Net Current Period Other Comprehensive Income | 267 | 410 | 802 | 1,231 | |
Ending Balance in AOCI | (13,604) | (14,745) | (13,604) | (14,745) | |
Commodity: | |||||
Subtotal - Commodity | 412 | 631 | 1,234 | 1,893 | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | 412 | 631 | 1,234 | 1,893 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 412 | 631 | 1,234 | 1,893 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 267 | 410 | 802 | 1,231 | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 412 | 631 | 1,234 | 1,893 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 267 | 410 | 802 | 1,231 | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 412 | 631 | 1,234 | 1,893 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 267 | 410 | 802 | 1,231 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 267 | 410 | 802 | 1,231 | |
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Income Tax (Expense) Credit | 145 | 221 | 432 | 29 | |
Gains and Losses on Available-for-Sale Securities | |||||
Income Tax (Expense) Credit | 145 | 221 | 432 | 29 | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | 145 | 221 | 432 | 29 | |
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Amounts Reclassified from AOCI | 11 | 42 | |||
Interest Rate and Foreign Currency: | |||||
Income Tax (Expense) Credit | 6 | 22 | 18 | 66 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 11 | 42 | |||
Gains and Losses on Available-for-Sale Securities | |||||
Income Tax (Expense) Credit | 6 | 22 | 18 | 66 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 11 | 42 | |||
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | 6 | 22 | 18 | 66 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 11 | 42 | |||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 11 | 42 | |||
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Ending Balance in AOCI | 0 | 0 | 0 | 0 | |
Commodity: | |||||
Purchased Electricity for Resale | 0 | 0 | 0 | (812) | |
Other Operation Expense | 0 | (7) | |||
Maintenance Expense | 0 | (7) | |||
Property, Plant and Equipment | 0 | (10) | |||
Regulatory Assets/(Liabilities), Net | [1] | 0 | 0 | 0 | (973) |
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Interest Expense | 412 | 631 | 1,234 | 1,893 | |
Gains and Losses on Available-for-Sale Securities | |||||
Interest Expense | 412 | 631 | 1,234 | 1,893 | |
Ohio Power Co [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 4,916 | 6,288 | 5,602 | 7,079 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | (344) | (343) | (1,030) | (1,134) | |
Net Current Period Other Comprehensive Income | (344) | (343) | (1,030) | (1,134) | |
Ending Balance in AOCI | 4,572 | 5,945 | 4,572 | 5,945 | |
Commodity: | |||||
Generation & Marketing Revenues | 1,953 | 1,564 | 6,416 | 4,628 | |
Purchased Electricity for Resale | 173,094 | 48,541 | 431,608 | 191,730 | |
Other Operation Expense | 170,144 | 145,163 | 446,817 | 428,074 | |
Maintenance Expense | 39,437 | 53,724 | 121,224 | 136,965 | |
Interest Rate and Foreign Currency: | |||||
Depreciation and Amortization Expense | 63,757 | 54,968 | 178,609 | 165,152 | |
Interest Expense | 32,593 | 31,171 | 96,313 | 96,937 | |
Income Tax (Expense) Credit | (38,541) | (28,865) | (100,641) | (98,759) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (344) | (343) | (1,030) | (1,134) | |
Gains and Losses on Available-for-Sale Securities | |||||
Interest Expense | 32,593 | 31,171 | 96,313 | 96,937 | |
Income Tax (Expense) Credit | (38,541) | (28,865) | (100,641) | (98,759) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (344) | (343) | (1,030) | (1,134) | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | (38,541) | (28,865) | (100,641) | (98,759) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (344) | (343) | (1,030) | (1,134) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (344) | (343) | (1,030) | (1,134) | |
Ohio Power Co [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Amounts Reclassified from AOCI | (344) | (343) | (1,030) | (1,134) | |
Commodity: | |||||
Subtotal - Commodity | (530) | (527) | (1,584) | (1,743) | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | (530) | (527) | (1,584) | (1,743) | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (530) | (527) | (1,584) | (1,743) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (344) | (343) | (1,030) | (1,134) | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (530) | (527) | (1,584) | (1,743) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (344) | (343) | (1,030) | (1,134) | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (530) | (527) | (1,584) | (1,743) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (344) | (343) | (1,030) | (1,134) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (344) | (343) | (1,030) | (1,134) | |
Ohio Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 0 | 0 | 0 | 105 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | 0 | 0 | 0 | (105) | |
Net Current Period Other Comprehensive Income | 0 | 0 | 0 | (105) | |
Ending Balance in AOCI | 0 | 0 | 0 | 0 | |
Commodity: | |||||
Subtotal - Commodity | 0 | 0 | 0 | (162) | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | 0 | 0 | 0 | (162) | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (162) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (105) | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (162) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (105) | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (162) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (105) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (105) | |
Ohio Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 4,916 | 6,288 | 5,602 | 6,974 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | (344) | (343) | (1,030) | (1,029) | |
Net Current Period Other Comprehensive Income | (344) | (343) | (1,030) | (1,029) | |
Ending Balance in AOCI | 4,572 | 5,945 | 4,572 | 5,945 | |
Commodity: | |||||
Subtotal - Commodity | (530) | (527) | (1,584) | (1,581) | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | (530) | (527) | (1,584) | (1,581) | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (530) | (527) | (1,584) | (1,581) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (344) | (343) | (1,030) | (1,029) | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (530) | (527) | (1,584) | (1,581) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (344) | (343) | (1,030) | (1,029) | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (530) | (527) | (1,584) | (1,581) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (344) | (343) | (1,030) | (1,029) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (344) | (343) | (1,030) | (1,029) | |
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Income Tax (Expense) Credit | (186) | (184) | (554) | (609) | |
Gains and Losses on Available-for-Sale Securities | |||||
Income Tax (Expense) Credit | (186) | (184) | (554) | (609) | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | (186) | (184) | (554) | (609) | |
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | |||||
Commodity: | |||||
Other Operation Expense | 0 | 0 | 0 | (11) | |
Maintenance Expense | 0 | 0 | 0 | (11) | |
Property, Plant and Equipment | 0 | 0 | 0 | (18) | |
Regulatory Assets/(Liabilities), Net | [1] | 0 | 0 | 0 | (122) |
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Depreciation and Amortization Expense | (4) | (3) | (10) | (9) | |
Interest Expense | (526) | (524) | (1,574) | (1,572) | |
Gains and Losses on Available-for-Sale Securities | |||||
Interest Expense | (526) | (524) | (1,574) | (1,572) | |
Public Service Co Of Oklahoma [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 4,563 | 5,322 | 4,943 | 5,758 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | (189) | (190) | (569) | (626) | |
Net Current Period Other Comprehensive Income | (189) | (190) | (569) | (626) | |
Ending Balance in AOCI | 4,374 | 5,132 | 4,374 | 5,132 | |
Commodity: | |||||
Generation & Marketing Revenues | 709 | 1,009 | 2,258 | 2,524 | |
Purchased Electricity for Resale | 103,226 | 117,521 | 253,785 | 301,816 | |
Other Operation Expense | 77,541 | 71,605 | 199,334 | 193,101 | |
Maintenance Expense | 27,239 | 21,800 | 74,322 | 76,223 | |
Interest Rate and Foreign Currency: | |||||
Depreciation and Amortization Expense | 30,832 | 24,496 | 90,148 | 73,085 | |
Interest Expense | 14,950 | 13,913 | 44,372 | 41,009 | |
Income Tax (Expense) Credit | (27,298) | (28,746) | (51,260) | (46,979) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (189) | (190) | (569) | (626) | |
Gains and Losses on Available-for-Sale Securities | |||||
Interest Expense | 14,950 | 13,913 | 44,372 | 41,009 | |
Income Tax (Expense) Credit | (27,298) | (28,746) | (51,260) | (46,979) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (189) | (190) | (569) | (626) | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | (27,298) | (28,746) | (51,260) | (46,979) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (189) | (190) | (569) | (626) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (189) | (190) | (569) | (626) | |
Public Service Co Of Oklahoma [Member] | Cash Flow Hedges [Member] | |||||
Commodity: | |||||
Subtotal - Commodity | (291) | (292) | (875) | (964) | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | (291) | (292) | (875) | (964) | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (291) | (292) | (875) | (964) | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (291) | (292) | (875) | (964) | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (291) | (292) | (875) | (964) | |
Public Service Co Of Oklahoma [Member] | Commodity [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 0 | 0 | 0 | 57 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | 0 | 0 | 0 | (57) | |
Net Current Period Other Comprehensive Income | 0 | 0 | 0 | (57) | |
Ending Balance in AOCI | 0 | 0 | 0 | 0 | |
Commodity: | |||||
Subtotal - Commodity | 0 | 0 | 0 | (88) | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | 0 | 0 | 0 | (88) | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (88) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (57) | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (88) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (57) | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (88) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (57) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (57) | |
Public Service Co Of Oklahoma [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 4,563 | 5,322 | 4,943 | 5,701 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | (189) | (190) | (569) | (569) | |
Net Current Period Other Comprehensive Income | (189) | (190) | (569) | (569) | |
Ending Balance in AOCI | 4,374 | 5,132 | 4,374 | 5,132 | |
Commodity: | |||||
Subtotal - Commodity | (291) | (292) | (875) | (876) | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | (291) | (292) | (875) | (876) | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (291) | (292) | (875) | (876) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (189) | (190) | (569) | (569) | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (291) | (292) | (875) | (876) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (189) | (190) | (569) | (569) | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (291) | (292) | (875) | (876) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (189) | (190) | (569) | (569) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (189) | (190) | (569) | (569) | |
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Amounts Reclassified from AOCI | (569) | (626) | |||
Interest Rate and Foreign Currency: | |||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (569) | (626) | |||
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (569) | (626) | |||
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (569) | (626) | |||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (569) | (626) | |||
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Income Tax (Expense) Credit | (102) | (102) | (306) | (338) | |
Gains and Losses on Available-for-Sale Securities | |||||
Income Tax (Expense) Credit | (102) | (102) | (306) | (338) | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | (102) | (102) | (306) | (338) | |
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | |||||
Commodity: | |||||
Other Operation Expense | 0 | 0 | 0 | (8) | |
Maintenance Expense | 0 | 0 | 0 | (9) | |
Property, Plant and Equipment | 0 | 0 | 0 | (13) | |
Regulatory Assets/(Liabilities), Net | [1] | 0 | 0 | 0 | (58) |
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Interest Expense | (291) | (292) | (875) | (876) | |
Gains and Losses on Available-for-Sale Securities | |||||
Interest Expense | (291) | (292) | (875) | (876) | |
Southwestern Electric Power Co [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | (6,811) | (7,844) | (7,466) | (8,444) | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | 192 | 332 | 847 | 932 | |
Net Current Period Other Comprehensive Income | 192 | 332 | 847 | 932 | |
Ending Balance in AOCI | (6,619) | (7,512) | (6,619) | (7,512) | |
Commodity: | |||||
Generation & Marketing Revenues | 618 | 521 | 1,486 | 1,570 | |
Purchased Electricity for Resale | 23,597 | 36,960 | 70,799 | 138,380 | |
Other Operation Expense | 81,391 | 68,601 | 214,835 | 206,442 | |
Maintenance Expense | 34,425 | 29,867 | 100,076 | 93,946 | |
Interest Rate and Foreign Currency: | |||||
Depreciation and Amortization Expense | 48,862 | 46,791 | 143,780 | 138,316 | |
Interest Expense | 29,263 | 31,644 | 91,423 | 95,258 | |
Income Tax (Expense) Credit | (37,358) | (31,042) | (85,417) | (60,252) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 192 | 332 | 847 | 932 | |
Gains and Losses on Available-for-Sale Securities | |||||
Interest Expense | 29,263 | 31,644 | 91,423 | 95,258 | |
Income Tax (Expense) Credit | (37,358) | (31,042) | (85,417) | (60,252) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 192 | 332 | 847 | 932 | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | (37,358) | (31,042) | (85,417) | (60,252) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 192 | 332 | 847 | 932 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 192 | 332 | 847 | 932 | |
Southwestern Electric Power Co [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Amounts Reclassified from AOCI | 432 | 567 | 1,566 | 1,636 | |
Commodity: | |||||
Subtotal - Commodity | 665 | 872 | 2,409 | 2,515 | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | 665 | 872 | 2,409 | 2,515 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 665 | 872 | 2,409 | 2,515 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 432 | 567 | 1,566 | 1,636 | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 665 | 872 | 2,409 | 2,515 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 432 | 567 | 1,566 | 1,636 | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 665 | 872 | 2,409 | 2,515 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 432 | 567 | 1,566 | 1,636 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 432 | 567 | 1,566 | 1,636 | |
Southwestern Electric Power Co [Member] | Pension and OPEB [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 3,091 | 4,325 | 3,570 | 4,794 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | (240) | (235) | (719) | (704) | |
Net Current Period Other Comprehensive Income | (240) | (235) | (719) | (704) | |
Ending Balance in AOCI | 2,851 | 4,090 | 2,851 | 4,090 | |
Commodity: | |||||
Subtotal - Commodity | (369) | (360) | (1,106) | (1,082) | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | (369) | (360) | (1,106) | (1,082) | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (369) | (360) | (1,106) | (1,082) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (240) | (235) | (719) | (704) | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (369) | (360) | (1,106) | (1,082) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (240) | (235) | (719) | (704) | |
Amortization of Pension and OPEB | |||||
Prior Service Cost (Credit) | (468) | (478) | (1,402) | (1,433) | |
Actuarial (Gains)/Losses | 99 | 118 | 296 | 351 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (369) | (360) | (1,106) | (1,082) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (240) | (235) | (719) | (704) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (240) | (235) | (719) | (704) | |
Southwestern Electric Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | 0 | 0 | 0 | 66 | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | 0 | 0 | 0 | (66) | |
Net Current Period Other Comprehensive Income | 0 | 0 | 0 | (66) | |
Ending Balance in AOCI | 0 | 0 | 0 | 0 | |
Commodity: | |||||
Subtotal - Commodity | 0 | 0 | 0 | (101) | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | 0 | 0 | 0 | (101) | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (101) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (66) | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (101) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (66) | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | (101) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (66) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | (66) | |
Southwestern Electric Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Beginning Balance in AOCI | (9,902) | (12,169) | (11,036) | (13,304) | |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 | |
Amounts Reclassified from AOCI | 432 | 567 | 1,566 | 1,702 | |
Net Current Period Other Comprehensive Income | 432 | 567 | 1,566 | 1,702 | |
Ending Balance in AOCI | (9,470) | (11,602) | (9,470) | (11,602) | |
Commodity: | |||||
Subtotal - Commodity | 665 | 872 | 2,409 | 2,616 | |
Interest Rate and Foreign Currency: | |||||
Subtotal - Interest Rate and Foreign Currency | 665 | 872 | 2,409 | 2,616 | |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 665 | 872 | 2,409 | 2,616 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 432 | 567 | 1,566 | 1,702 | |
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 665 | 872 | 2,409 | 2,616 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 432 | 567 | 1,566 | 1,702 | |
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 665 | 872 | 2,409 | 2,616 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 432 | 567 | 1,566 | 1,702 | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 432 | 567 | 1,566 | 1,702 | |
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Amounts Reclassified from AOCI | 192 | ||||
Interest Rate and Foreign Currency: | |||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 192 | ||||
Gains and Losses on Available-for-Sale Securities | |||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 192 | ||||
Amortization of Pension and OPEB | |||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 192 | ||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 192 | ||||
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Income Tax (Expense) Credit | 233 | 305 | 843 | 879 | |
Gains and Losses on Available-for-Sale Securities | |||||
Income Tax (Expense) Credit | 233 | 305 | 843 | 879 | |
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | 233 | 305 | 843 | 879 | |
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Amounts Reclassified from AOCI | (240) | (235) | |||
Interest Rate and Foreign Currency: | |||||
Income Tax (Expense) Credit | (129) | (125) | (387) | (378) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (240) | (235) | |||
Gains and Losses on Available-for-Sale Securities | |||||
Income Tax (Expense) Credit | (129) | (125) | (387) | (378) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (240) | (235) | |||
Amortization of Pension and OPEB | |||||
Income Tax (Expense) Credit | (129) | (125) | (387) | (378) | |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (240) | (235) | |||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (240) | (235) | |||
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | |||||
Commodity: | |||||
Other Operation Expense | 0 | 0 | 0 | (13) | |
Maintenance Expense | 0 | 0 | 0 | (10) | |
Property, Plant and Equipment | 0 | 0 | 0 | (11) | |
Regulatory Assets/(Liabilities), Net | [1] | 0 | 0 | 0 | (67) |
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | |||||
Interest Rate and Foreign Currency: | |||||
Interest Expense | 665 | 872 | 2,409 | 2,616 | |
Gains and Losses on Available-for-Sale Securities | |||||
Interest Expense | $ 665 | $ 872 | $ 2,409 | $ 2,616 | |
[1] | Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Rate Matters - Regulatory Asset
Rate Matters - Regulatory Assets (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | $ 4,950,000 | $ 4,264,000 |
Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 1,061,715 | 857,872 |
Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 818,168 | 536,152 |
Ohio Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 1,150,864 | 1,318,939 |
Public Service Co Of Oklahoma [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 180,605 | 154,327 |
Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 413,434 | 393,602 |
Regulatory Assets Pending Final Regulatory Approval [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 159,000 | 226,000 |
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 54,937 | 125,748 |
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 56,904 | 13,649 |
Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 10,483 | 10,483 |
Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 17,693 |
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 5,242 | 12,115 |
Amos Plant Transfer Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 1,950 | 1,377 |
Asset Retirement Obligation [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 1,516 | 1,144 |
Asset Retirement Obligation Costs Related to Retired Plants [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 59,000 | 0 |
Asset Retirement Obligation Costs Related to Retired Plants [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 32,128 | 0 |
Asset Retirement Obligation Costs Related to Retired Plants [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 27,079 | 0 |
Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 1,287 |
Carbon Capture and Storage Product Validation Facility [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 13,000 |
Carbon Capture and Storage Product Validation Facility - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 13,264 |
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 8,955 | 6,596 |
Deferred Cook Plant Life Cycle Management Project Costs - Michigan [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 3,445 | 1,222 |
Deferred Permit Fees Related to Retired Plants - WV [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 617 | 0 |
Expanded Net Energy Charge - Coal Inventory [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 3,421 |
Expanded Net Energy Charge - Construction Surcharge [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 2,307 |
IGCC Pre-Construction Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 11,000 |
IGCC Pre-Constructions Costs - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 10,838 |
Materials and Supplies Related to Retired Plants [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 20,000 | 0 |
Materials and Supplies Related to Retired Plants [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 8,592 | 0 |
Materials and Supplies Related to Retired Plants [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 11,652 | 0 |
Ormet Delayed Payment Arrangement [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 10,000 | 10,000 |
Ormet Delayed Payment Arrangement [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 10,483 | 10,483 |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 27,000 | 43,000 |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 168 |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 11 | 712 |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 1,079 |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 695 | 558 |
Peak Demand Reduction/Energy Efficiency - Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 12,000 | 9,000 |
Peak Demand Reduction/Energy Efficiency - Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 11,650 | 8,791 |
Rate Case Expenses [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 8,126 |
Rockport Dry Sorbent Injection System [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 1,865 | 148 |
Shipe Road Transmission Project [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 3,031 | 2,287 |
Storm Related Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 24,000 | 20,000 |
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 7,000 | 100,000 |
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 16,614 |
Storm Related Costs - Indiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 1,074 |
Storm Related Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 65,206 |
Stranded Costs on Abandoned Plants [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 3,897 | 3,897 |
Vegetation Management Program - West Virginia [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 0 | 20,000 |
Vegetation Management Program - West Virginia [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | $ 0 | $ 19,089 |
Rate Matters - East Companies
Rate Matters - East Companies (Details) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015USD ($)$ / MWD$ / MWh | Dec. 31, 2014USD ($) | |
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | $ 4,950,000 | $ 4,264,000 |
Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 1,061,715 | 857,872 |
Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 818,168 | 536,152 |
Ohio Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Regulatory Assets, Noncurrent | 1,150,864 | $ 1,318,939 |
Kentucky 2014 Base Rate Case [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Requested Net Increase in Rates | 70,000 | |
Recommended Net Increase in Rates as Proposed in Stipulation Agreement | 45,000 | |
Recommended Increase in Rider Rates as Proposed in Stipulation Agreement | 68,000 | |
Recommended Decrease in Annual Base Rates as Proposed in Stipulation Agreement | 23,000 | |
Amount of Storm Costs Recommended for Recovery as Proposed in Stipulation Agreement | 12,000 | |
Amount of Off-System Sales Margins Included in the Annual Base Rates as Proposed in Stipulation Agreement | $ 15,000 | |
Percentage of Off-System Sales Margins Above the Amount in Base Rates to be Shared with Customers as Proposed in Stipulation Agreement | 75.00% | |
Percentage of Off-System Sales Margins Above the Amount in Base Rates to be Retained by KPCo as Proposed in Stipulation Agreement | 25.00% | |
Approved Net Revenue Increase | $ 45,000 | |
Amount of IGCC and Carbon Capture Costs Approved for Recovery | $ 2,000 | |
Recovery Period of Approved IGCC and Carbon Capture Costs | 25 years | |
Kentucky Fuel Adjustment Clause Review [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Amount of Regulatory Disallowance Resulting from a Commission Order | $ 36,000 | |
Kingsport 2015 Base Rate Case [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Requested Base Rate Increase | $ 12,000 | |
Requested Return on Equity | 10.66% | |
Ohio Electric Security Plan Filing [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
PUCO-ordered Fixed Price per MW Day for Customers Who Switch During ESP Period | $ / MWD | 188.88 | |
Reliability Pricing Model Rate per MW Day in Effect through May 2014 | $ / MWD | 34 | |
Reliability Pricing Model Rate per MW Day in Effect from June 2014 through May 2015 | $ / MWD | 150 | |
Retail Stability Rider through May 2014 ($ Per MWh) | $ / MWh | 3.50 | |
Retail Stability Rider for the Period June 2014 through May 2015 ($ per MWh) | $ / MWh | 4 | |
Amount of Retail Stability Rider Applied to the Deferred Capacity Costs ($ per MWh) | $ / MWh | 1 | |
Retail Stability Rider Rate to be Continued Until Capacity Deferral Balance is Collected as Ordered by the PUCO ($ per MWh) | $ / MWh | 4 | |
Deferred Capacity Costs Recovery Period as Ordered by PUCO (in months) | 32 months | |
Annual Retail Share of Fixed Fuel Costs | $ 90,000 | |
Approved Return On Equity | 10.20% | |
Future Commitment to Support the Development of a Large Solar Farm | $ 20,000 | |
Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
PUCO-ordered Fixed Price per MW Day for Customers Who Switch During ESP Period | $ / MWD | 188.88 | |
Reliability Pricing Model Rate per MW Day in Effect through May 2014 | $ / MWD | 34 | |
Reliability Pricing Model Rate per MW Day in Effect from June 2014 through May 2015 | $ / MWD | 150 | |
Retail Stability Rider through May 2014 ($ Per MWh) | $ / MWh | 3.50 | |
Retail Stability Rider for the Period June 2014 through May 2015 ($ per MWh) | $ / MWh | 4 | |
Amount of Retail Stability Rider Applied to the Deferred Capacity Costs ($ per MWh) | $ / MWh | 1 | |
Retail Stability Rider Rate to be Continued Until Capacity Deferral Balance is Collected as Ordered by the PUCO ($ per MWh) | $ / MWh | 4 | |
Deferred Capacity Costs Recovery Period as Ordered by PUCO (in months) | 32 months | |
Annual Retail Share of Fixed Fuel Costs | $ 90,000 | |
Approved Return On Equity | 10.20% | |
Future Commitment to Support the Development of a Large Solar Farm | $ 20,000 | |
Ohio Fuel Adjustment Clause Audit - 2009 [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
2008 Coal Contract Settlement Proceeds to be Applied to Deferred Fuel Balance as Originally Ordered by the PUCO | 65,000 | |
Net Favorable Fuel Adjustment Recorded in 2012 Based on Fuel Adjustment Clause Audit Rehearing | 30,000 | |
Ohio Fuel Adjustment Clause Audit - 2009 [Member] | Ohio Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
2008 Coal Contract Settlement Proceeds to be Applied to Deferred Fuel Balance as Originally Ordered by the PUCO | 65,000 | |
Net Favorable Fuel Adjustment Recorded in 2012 Based on Fuel Adjustment Clause Audit Rehearing | 30,000 | |
Special Rate Mechanism For Ormet [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Amount of Foregone Revenues to be Collected Through the Economic Development Rider as Approved in the Economic Development Rider Filing | 39,000 | |
Remaining Ormet Deferral Allowed to be Requested Upon PUCO Adoption of Ormet Stipulation Agreement | 10,000 | |
Amount of Remaining Foregone Revenues Objected to by an Intervenor | 5,000 | |
Deferred Fuel Adjustment Clause Related to Ormet Interim Arrangement as of September 2009 | 64,000 | |
Unrecognized Equity Carrying Costs Related to Ormet Interim Arrangement as of September 2009 | 2,000 | |
Special Rate Mechanism For Ormet [Member] | Ohio Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Amount of Foregone Revenues to be Collected Through the Economic Development Rider as Approved in the Economic Development Rider Filing | 39,000 | |
Remaining Ormet Deferral Allowed to be Requested Upon PUCO Adoption of Ormet Stipulation Agreement | 10,000 | |
Amount of Remaining Foregone Revenues Objected to by an Intervenor | 5,000 | |
Deferred Fuel Adjustment Clause Related to Ormet Interim Arrangement as of September 2009 | 64,000 | |
Unrecognized Equity Carrying Costs Related to Ormet Interim Arrangement as of September 2009 | 2,000 | |
Transmission Distribution and Storage System Improvement Charge (TDSIC) [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Estimated Cost Of Capital Improvements And Associated Operation And Maintenance Expenses | 787,000 | |
Reduction to the Estimated Cost of Capital Improvements and Associated Operation and Maintenance Expenses | 117,000 | |
Transmission Distribution and Storage System Improvement Charge (TDSIC) [Member] | Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Estimated Cost Of Capital Improvements And Associated Operation And Maintenance Expenses | 787,000 | |
Reduction to the Estimated Cost of Capital Improvements and Associated Operation and Maintenance Expenses | 117,000 | |
Virginia Regulatory Asset Proceeding - 2015 [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Amounts Of Regulatory Assets Under Review In Separate Proceeding | 11,000 | |
Virginia Regulatory Asset Proceeding - 2015 [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Amounts Of Regulatory Assets Under Review In Separate Proceeding | $ 11,000 | |
West Virginia Base Rate Case [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved Return On Equity | 9.75% | |
Approved Base Rate Increase | $ 99,000 | |
Amount of Annual Delayed Customer Billing to Residential Customers | 25,000 | |
Approved Annual Vegetation Management Rider | 45,000 | |
Approved Annual Amortization Of Certain Deferred Costs | $ 89,000 | |
West Virginia Base Rate Case [Member] | Appalachian Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved Return On Equity | 9.75% | |
Approved Base Rate Increase | $ 85,000 | |
Amount of Annual Delayed Customer Billing to Residential Customers | 22,000 | |
Approved Annual Vegetation Management Rider | 38,000 | |
Approved Annual Amortization Of Certain Deferred Costs | 77,000 | |
Deferred Capacity Costs [Member] | Ohio Electric Security Plan Filing [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Capacity Deferral Balance as of May 2015 Subject to Audit by the PUCO | 444,000 | |
Regulatory Assets, Noncurrent | 392,000 | |
Amount of Deferred Capacity Costs Collected from Customers | 183,000 | |
Deferred Capacity Costs [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Capacity Deferral Balance as of May 2015 Subject to Audit by the PUCO | 444,000 | |
Regulatory Assets, Noncurrent | 392,000 | |
Amount of Deferred Capacity Costs Collected from Customers | 183,000 | |
Big Sandy Plant, Unit 2 [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant | $ 194,000 | |
Amortization Period of Approved Regulatory Assets Related to Plant Retirement | 25 years | |
Tanners Creek Plant, Units 1 - 4 [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant | $ 265,000 | |
Amortization Period of Approved Regulatory Assets Related to Plant Retirement | 29 years | |
Amount Reclassified as Regulatory Assets Upon Plant Retirement Currently Not Being Amortized | $ 38,000 | |
Tanners Creek Plant, Units 1 - 4 [Member] | Indiana Michigan Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant | $ 265,000 | |
Amortization Period of Approved Regulatory Assets Related to Plant Retirement | 29 years | |
Amount Reclassified as Regulatory Assets Upon Plant Retirement Currently Not Being Amortized | $ 38,000 |
Rate Matters - West Companies (
Rate Matters - West Companies (Details) - USD ($) $ in Thousands | 1 Months Ended | 9 Months Ended | |
Oct. 22, 2015 | Sep. 30, 2015 | Dec. 31, 2014 | |
Public Utilities, General Disclosures [Line Items] | |||
Construction Work in Progress | $ 4,008,000 | $ 3,215,000 | |
Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Construction Work in Progress | 274,470 | 204,753 | |
Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Construction Work in Progress | $ 681,991 | $ 471,980 | |
Louisiana 2012 Formula Rate Filing [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Louisiana Jurisdictional Share of the Turk Plant | 29.00% | ||
Net Increase in Louisiana Total Rates per the Settlement Agreement | $ 2,000 | ||
Base Rate Increase per the Settlement Agreement | 85,000 | ||
Fuel Rate Decrease per the Settlement Agreement | $ 83,000 | ||
Return on Common Equity per the Settlement Agreement | 10.00% | ||
Reduction to Requested Revenue Increase as Approved in Stipulation Agreement | $ 3,000 | ||
Louisiana 2012 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Louisiana Jurisdictional Share of the Turk Plant | 29.00% | ||
Net Increase in Louisiana Total Rates per the Settlement Agreement | $ 2,000 | ||
Base Rate Increase per the Settlement Agreement | 85,000 | ||
Fuel Rate Decrease per the Settlement Agreement | $ 83,000 | ||
Return on Common Equity per the Settlement Agreement | 10.00% | ||
Reduction to Requested Revenue Increase as Approved in Stipulation Agreement | $ 3,000 | ||
Louisiana 2014 Formula Rate Filing [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested Annual Increase | 5,000 | ||
Additional Requested Annual Increase | 15,000 | ||
Requested Total Annual Increase | 20,000 | ||
Amount of Interim Rates Implemented in January 2015 as Approved in Partial Settlement Agreement | 15,000 | ||
Louisiana 2014 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested Annual Increase | 5,000 | ||
Additional Requested Annual Increase | 15,000 | ||
Requested Total Annual Increase | 20,000 | ||
Amount of Interim Rates Implemented in January 2015 as Approved in Partial Settlement Agreement | 15,000 | ||
Louisiana 2015 Formula Rate Filing [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested Annual Increase | 14,000 | ||
Louisiana 2015 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested Annual Increase | 14,000 | ||
Oklahoma Base Rate Case - 2014 [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Fourteen Months Of Revenues Beginning November 2014 Related To Advanced Metering Costs As Approved In Stipulation Agreement | 24,000 | ||
2016 Revenues Related To Advanced Metering Costs As Approved In Stipulation Agreement | $ 27,000 | ||
Return On Common Equity For AFUDC And Factoring As Approved In Stipulation Agreement | 9.85% | ||
Oklahoma Base Rate Case - 2014 [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Fourteen Months Of Revenues Beginning November 2014 Related To Advanced Metering Costs As Approved In Stipulation Agreement | $ 24,000 | ||
2016 Revenues Related To Advanced Metering Costs As Approved In Stipulation Agreement | $ 27,000 | ||
Return On Common Equity For AFUDC And Factoring As Approved In Stipulation Agreement | 9.85% | ||
Oklahoma Base Rate Case - 2015 [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested Annual Increase | $ 137,000 | ||
Requested Base Rate Increase | 89,000 | ||
Amount of Increased Depreciation Expense Requested | 48,000 | ||
Amount of Increase Related to Environmental Controls | 44,000 | ||
Amount Of Requested Increase Related To Environmental Consumable Costs In Fuel Adjustment Clause | $ 4,000 | ||
Requested Return on Equity | 10.50% | ||
Future Incremental Purchased Capacity and Energy Costs Related to Environmental Projects | $ 35,000 | ||
Oklahoma Base Rate Case - 2015 [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested Annual Increase | 137,000 | ||
Requested Base Rate Increase | 89,000 | ||
Amount of Increased Depreciation Expense Requested | 48,000 | ||
Amount of Increase Related to Environmental Controls | 44,000 | ||
Amount Of Requested Increase Related To Environmental Consumable Costs In Fuel Adjustment Clause | $ 4,000 | ||
Requested Return on Equity | 10.50% | ||
Future Incremental Purchased Capacity and Energy Costs Related to Environmental Projects | $ 35,000 | ||
Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 4 [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Property, Plant and Equipment, Net | 94,000 | ||
Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 4 [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Property, Plant and Equipment, Net | 94,000 | ||
Texas Base Rate Case [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
2013 Reversal of Previously Recorded Regulatory Disallowances | 114,000 | ||
Resulting Approved Base Rate Increase | 52,000 | ||
Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
2013 Reversal of Previously Recorded Regulatory Disallowances | 114,000 | ||
Resulting Approved Base Rate Increase | 52,000 | ||
Texas Base Rate Case [Member] | Welsh Plant, Unit 2 [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Property, Plant and Equipment, Net | 83,000 | ||
Texas Base Rate Case [Member] | Welsh Plant, Unit 2 [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Property, Plant and Equipment, Net | 83,000 | ||
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Projected Capital Costs | 700,000 | ||
Construction Work in Progress | 303,000 | ||
Remaining Contractual Construction Obligations | 62,000 | ||
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Projected Capital Costs | 700,000 | ||
Construction Work in Progress | 303,000 | ||
Remaining Contractual Construction Obligations | 62,000 | ||
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Welsh Plant, Units 1 and 3 [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Property, Plant and Equipment, Net | 529,000 | ||
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Welsh Plant, Units 1 and 3 [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Property, Plant and Equipment, Net | 529,000 | ||
Subsequent Event [Member] | Minimum [Member] | Oklahoma Base Rate Case - 2015 [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Intervenor Recommended Increase to Annual Revenue and/or Rider | $ 10,000 | ||
Intervenor Recommended Return On Common Equity Range | 8.75% | ||
Intervenor Recommended Increase to Depreciation Expense | $ 23,000 | ||
Subsequent Event [Member] | Minimum [Member] | Oklahoma Base Rate Case - 2015 [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Intervenor Recommended Increase to Annual Revenue and/or Rider | $ 10,000 | ||
Intervenor Recommended Return On Common Equity Range | 8.75% | ||
Intervenor Recommended Increase to Depreciation Expense | $ 23,000 | ||
Subsequent Event [Member] | Maximum [Member] | Oklahoma Base Rate Case - 2015 [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Intervenor Recommended Increase to Annual Revenue and/or Rider | $ 31,000 | ||
Intervenor Recommended Return On Common Equity Range | 9.30% | ||
Intervenor Recommended Increase to Depreciation Expense | $ 46,000 | ||
Subsequent Event [Member] | Maximum [Member] | Oklahoma Base Rate Case - 2015 [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Intervenor Recommended Increase to Annual Revenue and/or Rider | $ 31,000 | ||
Intervenor Recommended Return On Common Equity Range | 9.30% | ||
Intervenor Recommended Increase to Depreciation Expense | $ 46,000 | ||
Environmental Controls Projects [Member] | Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 3 and Comanche Plant [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Projected Capital Costs | 219,000 | ||
Construction Work in Progress | 162,000 | ||
Environmental Controls Projects [Member] | Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 3 and Comanche Plant [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Projected Capital Costs | 219,000 | ||
Construction Work in Progress | 162,000 | ||
Mercury and Air Toxic Standards [Member] | Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Projected Capital Costs | 410,000 | ||
Mercury and Air Toxic Standards [Member] | Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Projected Capital Costs | $ 410,000 |
Commitments, Guarantees and C49
Commitments, Guarantees and Contingencies (Details) $ in Thousands | 9 Months Ended |
Sep. 30, 2015USD ($) | |
Letters of Credit [Member] | |
Maximum Future Payments for Letters of Credit [Abstract] | |
Maximum Future Payments for Letters of Credit | $ 33,000 |
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract] | |
Variable Rate PCBs Supported | 477,000 |
Bilateral Letters of Credit | 483,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Revolving Credit Facilities | 3,500,000 |
Letters of Credit Limit | 1,200,000 |
Maximum Future Payments for Letters of Credit | 33,000 |
Uncommitted Facility | 150,000 |
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility | 122,000 |
Variable Rate PCBs Supported | 477,000 |
Bilateral Letters of Credit | 483,000 |
Master Lease Agreements [Member] | |
Maximum Potential Loss on Master Lease Agreements [Abstract] | |
Max Potential Loss on Master Lease Agreements | 35,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Max Potential Loss on Master Lease Agreements | 35,000 |
Guarantees of Third Party Obligations [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Guarantees of Mine Reclamation, Amount | 115,000 |
Estimated Final Cost Mine Reclamation | 58,000 |
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs | 65,000 |
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent | 16,000 |
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent | 49,000 |
Indiana Michigan Power Co [Member] | Letters of Credit [Member] | |
Maximum Future Payments for Letters of Credit [Abstract] | |
Maximum Future Payments for Letters of Credit | 35 |
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract] | |
Variable Rate PCBs Supported | 77,000 |
Bilateral Letters of Credit | 77,886 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Maximum Future Payments for Letters of Credit | 35 |
Variable Rate PCBs Supported | 77,000 |
Bilateral Letters of Credit | 77,886 |
Indiana Michigan Power Co [Member] | Master Lease Agreements [Member] | |
Maximum Potential Loss on Master Lease Agreements [Abstract] | |
Max Potential Loss on Master Lease Agreements | 3,448 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Max Potential Loss on Master Lease Agreements | 3,448 |
Future Minimum Lease Obligation for Remaining Railcars | $ 11,000 |
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor Current Term | 83.00% |
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor End of Max Lease Term | 77.00% |
Maximum Potential Loss on Guarantee of Return-and-Sale Option | $ 9,000 |
Southwestern Electric Power Co [Member] | Master Lease Agreements [Member] | |
Maximum Potential Loss on Master Lease Agreements [Abstract] | |
Max Potential Loss on Master Lease Agreements | 3,086 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Max Potential Loss on Master Lease Agreements | 3,086 |
Future Minimum Lease Obligation for Remaining Railcars | $ 12,000 |
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor Current Term | 83.00% |
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor End of Max Lease Term | 77.00% |
Maximum Potential Loss on Guarantee of Return-and-Sale Option | $ 10,000 |
Southwestern Electric Power Co [Member] | Guarantees of Third Party Obligations [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Guarantees of Mine Reclamation, Amount | 115,000 |
Estimated Final Cost Mine Reclamation | 58,000 |
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs | 65,000 |
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent | 16,000 |
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent | 49,000 |
Ohio Power Co [Member] | Letters of Credit [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility | 4,200 |
Ohio Power Co [Member] | Master Lease Agreements [Member] | |
Maximum Potential Loss on Master Lease Agreements [Abstract] | |
Max Potential Loss on Master Lease Agreements | 6,075 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Max Potential Loss on Master Lease Agreements | 6,075 |
Appalachian Power Co [Member] | Letters of Credit [Member] | |
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract] | |
Variable Rate PCBs Supported | 229,650 |
Bilateral Letters of Credit | 232,293 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Variable Rate PCBs Supported | 229,650 |
Bilateral Letters of Credit | 232,293 |
Appalachian Power Co [Member] | Master Lease Agreements [Member] | |
Maximum Potential Loss on Master Lease Agreements [Abstract] | |
Max Potential Loss on Master Lease Agreements | 5,396 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Max Potential Loss on Master Lease Agreements | 5,396 |
Public Service Co Of Oklahoma [Member] | Master Lease Agreements [Member] | |
Maximum Potential Loss on Master Lease Agreements [Abstract] | |
Max Potential Loss on Master Lease Agreements | 2,785 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Max Potential Loss on Master Lease Agreements | 2,785 |
Superfund and State Remediation [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Expense Recorded Due to Remediation Work Remaining Provision | 8,000 |
Superfund and State Remediation [Member] | Indiana Michigan Power Co [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Expense Recorded Due to Remediation Work Remaining Provision | 8,000 |
Wage and Hours Lawsuit [Member] | Maximum [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Range of Possible Loss | 30,000 |
Wage and Hours Lawsuit [Member] | Maximum [Member] | Public Service Co Of Oklahoma [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Range of Possible Loss | $ 30,000 |
Dispositions, Assets and Liab50
Dispositions, Assets and Liabilities Held for Sale and Discontinued Operations (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | ||
Payment on Sale of Muskingum River Plant | $ 48 | |||||
Gain on Disposition of Assets | 32 | |||||
Accounts Receivable | $ 55 | 55 | $ 91 | |||
Property, Plant and Equipment | 506 | 506 | 482 | |||
Other Classes of Assets That Are Not Major | 47 | 47 | 52 | |||
Total Assets Classified as Held for Sale on the Condensed Consolidated Balance Sheets | 608 | 608 | 625 | |||
Long-term Debt | 81 | 81 | 83 | |||
Obligations Under Capital Leases | 228 | 228 | 189 | |||
Other Classes of Liabilities That Are Not Major | 165 | 165 | 163 | |||
Total Liabilities Classified as Held for Sale on the Condensed Consolidated Balance Sheets | [1] | 474 | 474 | $ 435 | ||
Other Revenues | 129 | $ 141 | 372 | $ 435 | ||
Other Operation Expense | 96 | 102 | 273 | 342 | ||
Maintenance Expense | 4 | 8 | 20 | 24 | ||
Depreciation and Amortization Expense | 9 | 8 | 27 | 23 | ||
Other Expense | 8 | 7 | 24 | 22 | ||
Total Expense | 117 | 125 | 344 | 411 | ||
Pretax Income of Discontinued Operations | 12 | 16 | 28 | 24 | ||
Income Tax Expense | 4 | 5 | 10 | 8 | ||
Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income | $ 8 | $ 11 | $ 18 | $ 16 | ||
[1] | Amounts include debt related to AEPRO. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. |
Benefit Plans (Details)
Benefit Plans (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Pension Plans [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | $ 23,000 | $ 18,000 | $ 70,000 | $ 54,000 |
Interest Cost | 51,000 | 55,000 | 154,000 | 166,000 |
Expected Return on Plan Assets | (69,000) | (65,000) | (206,000) | (196,000) |
Amortization of Prior Service Cost (Credit) | 1,000 | 1,000 | 2,000 | 2,000 |
Amortization of Net Actuarial Loss | 27,000 | 31,000 | 80,000 | 93,000 |
Net Periodic Benefit Cost (Credit) | 33,000 | 40,000 | 100,000 | 119,000 |
Pension Plans [Member] | Appalachian Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 2,175 | 1,759 | 6,525 | 5,277 |
Interest Cost | 6,679 | 7,406 | 20,037 | 22,218 |
Expected Return on Plan Assets | (8,745) | (8,482) | (26,236) | (25,445) |
Amortization of Prior Service Cost (Credit) | 45 | 49 | 135 | 148 |
Amortization of Net Actuarial Loss | 3,474 | 4,149 | 10,421 | 12,445 |
Net Periodic Benefit Cost (Credit) | 3,628 | 4,881 | 10,882 | 14,643 |
Pension Plans [Member] | Indiana Michigan Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 3,217 | 2,517 | 9,651 | 7,551 |
Interest Cost | 6,114 | 6,573 | 18,344 | 19,720 |
Expected Return on Plan Assets | (8,115) | (7,749) | (24,347) | (23,245) |
Amortization of Prior Service Cost (Credit) | 45 | 49 | 136 | 146 |
Amortization of Net Actuarial Loss | 3,145 | 3,647 | 9,434 | 10,939 |
Net Periodic Benefit Cost (Credit) | 4,406 | 5,037 | 13,218 | 15,111 |
Pension Plans [Member] | Ohio Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 1,671 | 1,285 | 5,015 | 3,855 |
Interest Cost | 5,071 | 5,527 | 15,211 | 16,579 |
Expected Return on Plan Assets | (6,878) | (6,607) | (20,634) | (19,820) |
Amortization of Prior Service Cost (Credit) | 35 | 40 | 105 | 118 |
Amortization of Net Actuarial Loss | 2,644 | 3,105 | 7,932 | 9,316 |
Net Periodic Benefit Cost (Credit) | 2,543 | 3,350 | 7,629 | 10,048 |
Pension Plans [Member] | Public Service Co Of Oklahoma [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 1,598 | 1,301 | 4,796 | 3,905 |
Interest Cost | 2,731 | 3,015 | 8,194 | 9,043 |
Expected Return on Plan Assets | (3,786) | (3,651) | (11,358) | (10,953) |
Amortization of Prior Service Cost (Credit) | 63 | 74 | 189 | 222 |
Amortization of Net Actuarial Loss | 1,418 | 1,689 | 4,252 | 5,065 |
Net Periodic Benefit Cost (Credit) | 2,024 | 2,428 | 6,073 | 7,282 |
Pension Plans [Member] | Southwestern Electric Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 2,081 | 1,655 | 6,244 | 4,964 |
Interest Cost | 2,932 | 3,163 | 8,796 | 9,488 |
Expected Return on Plan Assets | (4,008) | (3,857) | (12,024) | (11,571) |
Amortization of Prior Service Cost (Credit) | 78 | 87 | 232 | 262 |
Amortization of Net Actuarial Loss | 1,506 | 1,762 | 4,520 | 5,285 |
Net Periodic Benefit Cost (Credit) | 2,589 | 2,810 | 7,768 | 8,428 |
Other Postretirement Benefit Plans [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 3,000 | 4,000 | 9,000 | 11,000 |
Interest Cost | 15,000 | 16,000 | 43,000 | 50,000 |
Expected Return on Plan Assets | (28,000) | (28,000) | (83,000) | (84,000) |
Amortization of Prior Service Cost (Credit) | (18,000) | (18,000) | (52,000) | (52,000) |
Amortization of Net Actuarial Loss | 5,000 | 6,000 | 14,000 | 17,000 |
Net Periodic Benefit Cost (Credit) | (23,000) | (20,000) | (69,000) | (58,000) |
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 286 | 362 | 857 | 1,086 |
Interest Cost | 2,584 | 3,197 | 7,753 | 9,591 |
Expected Return on Plan Assets | (4,529) | (4,634) | (13,587) | (13,900) |
Amortization of Prior Service Cost (Credit) | (2,513) | (2,512) | (7,538) | (7,537) |
Amortization of Net Actuarial Loss | 900 | 1,145 | 2,699 | 3,436 |
Net Periodic Benefit Cost (Credit) | (3,272) | (2,442) | (9,816) | (7,324) |
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 406 | 486 | 1,219 | 1,460 |
Interest Cost | 1,592 | 1,909 | 4,776 | 5,728 |
Expected Return on Plan Assets | (3,304) | (3,363) | (9,912) | (10,090) |
Amortization of Prior Service Cost (Credit) | (2,355) | (2,355) | (7,066) | (7,066) |
Amortization of Net Actuarial Loss | 506 | 592 | 1,519 | 1,776 |
Net Periodic Benefit Cost (Credit) | (3,155) | (2,731) | (9,464) | (8,192) |
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 216 | 256 | 647 | 769 |
Interest Cost | 1,615 | 1,900 | 4,845 | 5,701 |
Expected Return on Plan Assets | (3,376) | (3,379) | (10,130) | (10,139) |
Amortization of Prior Service Cost (Credit) | (1,731) | (1,731) | (5,192) | (5,192) |
Amortization of Net Actuarial Loss | 517 | 595 | 1,552 | 1,785 |
Net Periodic Benefit Cost (Credit) | (2,759) | (2,359) | (8,278) | (7,076) |
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 170 | 209 | 509 | 629 |
Interest Cost | 759 | 893 | 2,277 | 2,680 |
Expected Return on Plan Assets | (1,578) | (1,575) | (4,732) | (4,725) |
Amortization of Prior Service Cost (Credit) | (1,072) | (1,072) | (3,217) | (3,217) |
Amortization of Net Actuarial Loss | 242 | 278 | 725 | 832 |
Net Periodic Benefit Cost (Credit) | (1,479) | (1,267) | (4,438) | (3,801) |
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 211 | 253 | 632 | 759 |
Interest Cost | 837 | 998 | 2,512 | 2,994 |
Expected Return on Plan Assets | (1,735) | (1,754) | (5,206) | (5,262) |
Amortization of Prior Service Cost (Credit) | (1,289) | (1,289) | (3,867) | (3,867) |
Amortization of Net Actuarial Loss | 266 | 309 | 798 | 926 |
Net Periodic Benefit Cost (Credit) | $ (1,710) | $ (1,483) | $ (5,131) | $ (4,450) |
Business Segments (Details)
Business Segments (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | ||||
Reportable Segment Information | ||||||||
Revenues | $ 4,432 | $ 4,161 | $ 12,839 | $ 12,559 | ||||
Income from Continuing Operations | 512 | 483 | 1,564 | 1,430 | ||||
Income from Discontinued Operations, Net of Tax | 8 | 11 | 18 | 16 | ||||
NET INCOME (LOSS) | 520 | 494 | 1,582 | 1,446 | ||||
Balance Sheet Information | ||||||||
Total Property, Plant and Equipment | 64,826 | 64,826 | $ 63,606 | |||||
Accumulated Depreciation and Amortization | 19,588 | 19,588 | 19,971 | |||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 45,238 | 45,238 | 43,635 | |||||
Assets Held for Sale | 608 | 608 | 625 | |||||
Total Assets | 61,099 | 61,099 | 59,633 | |||||
Long-term Debt Due Within One Year - Affiliated | 0 | 0 | 0 | |||||
Long-term Debt Due Within One Year | 1,826 | 1,826 | 2,500 | |||||
Long-term Debt - Affiliated | 0 | 0 | 0 | |||||
Long-term Debt | 17,600 | 17,600 | 16,101 | |||||
Total Long-term Debt Outstanding | 19,426 | 19,426 | 18,601 | |||||
Liabilities Held for Sale | [1] | 474 | 474 | 435 | ||||
Reconciling Adjustments [Member] | ||||||||
Reportable Segment Information | ||||||||
NET INCOME (LOSS) | 0 | 0 | 0 | 0 | ||||
Balance Sheet Information | ||||||||
Total Property, Plant and Equipment | [2] | (279) | (279) | (271) | ||||
Accumulated Depreciation and Amortization | [2] | (109) | (109) | (99) | ||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | [2] | (170) | (170) | (172) | ||||
Assets Held for Sale | 0 | 0 | 0 | |||||
Total Assets | [2],[3] | (21,089) | (21,089) | (20,346) | ||||
Long-term Debt Due Within One Year - Affiliated | 0 | 0 | (197) | |||||
Long-term Debt Due Within One Year | 0 | 0 | 0 | |||||
Long-term Debt - Affiliated | (52) | (52) | (52) | |||||
Long-term Debt | 0 | 0 | 0 | |||||
Total Long-term Debt Outstanding | (52) | (52) | (249) | |||||
Liabilities Held for Sale | 0 | 0 | 0 | |||||
Vertically Integrated Utilities [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | 2,436 | 2,432 | [4] | 7,082 | 7,217 | [4] | ||
Revenues | 2,471 | 2,450 | 7,159 | 7,288 | ||||
Income from Continuing Operations | 275 | 220 | 783 | 654 | ||||
Income from Discontinued Operations, Net of Tax | 0 | 0 | 0 | 0 | ||||
NET INCOME (LOSS) | 275 | 220 | 783 | 654 | ||||
Balance Sheet Information | ||||||||
Total Property, Plant and Equipment | 39,981 | 39,981 | 39,402 | |||||
Accumulated Depreciation and Amortization | 12,483 | 12,483 | 12,773 | |||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 27,498 | 27,498 | 26,629 | |||||
Assets Held for Sale | 0 | 0 | 0 | |||||
Total Assets | 35,272 | 35,272 | 33,750 | |||||
Long-term Debt Due Within One Year - Affiliated | 0 | 0 | 111 | |||||
Long-term Debt Due Within One Year | 949 | 949 | 1,352 | |||||
Long-term Debt - Affiliated | 20 | 20 | 20 | |||||
Long-term Debt | 9,900 | 9,900 | 8,634 | |||||
Total Long-term Debt Outstanding | 10,869 | 10,869 | 10,117 | |||||
Liabilities Held for Sale | 0 | 0 | 0 | |||||
Vertically Integrated Utilities [Member] | Significant Reconciling Items [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | 35 | 18 | [4] | 77 | 71 | [4] | ||
Transmission And Distribution Utilities [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | 1,164 | 1,163 | 3,378 | 3,388 | ||||
Revenues | 1,189 | 1,231 | 3,520 | 3,580 | ||||
Income from Continuing Operations | 113 | 92 | 288 | 279 | ||||
Income from Discontinued Operations, Net of Tax | 0 | 0 | 0 | 0 | ||||
NET INCOME (LOSS) | 113 | 92 | 288 | 279 | ||||
Balance Sheet Information | ||||||||
Total Property, Plant and Equipment | 13,707 | 13,707 | 13,024 | |||||
Accumulated Depreciation and Amortization | 3,603 | 3,603 | 3,481 | |||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 10,104 | 10,104 | 9,543 | |||||
Assets Held for Sale | 0 | 0 | 0 | |||||
Total Assets | 14,441 | 14,441 | 14,495 | |||||
Long-term Debt Due Within One Year - Affiliated | 0 | 0 | 0 | |||||
Long-term Debt Due Within One Year | 724 | 724 | 405 | |||||
Long-term Debt - Affiliated | 0 | 0 | 0 | |||||
Long-term Debt | 4,888 | 4,888 | 5,256 | |||||
Total Long-term Debt Outstanding | 5,612 | 5,612 | 5,661 | |||||
Liabilities Held for Sale | 0 | 0 | 0 | |||||
Transmission And Distribution Utilities [Member] | Significant Reconciling Items [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | 25 | 68 | 142 | 192 | ||||
AEP Transmission Holdco [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | 27 | 21 | 74 | 54 | ||||
Revenues | 88 | 55 | 245 | 140 | ||||
Income from Continuing Operations | 46 | 43 | 148 | 114 | ||||
Income from Discontinued Operations, Net of Tax | 0 | 0 | 0 | 0 | ||||
NET INCOME (LOSS) | 46 | 43 | 148 | 114 | ||||
Balance Sheet Information | ||||||||
Total Property, Plant and Equipment | 3,594 | 3,594 | 2,714 | |||||
Accumulated Depreciation and Amortization | 43 | 43 | 25 | |||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 3,551 | 3,551 | 2,689 | |||||
Assets Held for Sale | 0 | 0 | 0 | |||||
Total Assets | 4,362 | 4,362 | 3,575 | |||||
Long-term Debt Due Within One Year - Affiliated | 0 | 0 | 0 | |||||
Long-term Debt Due Within One Year | 0 | 0 | 0 | |||||
Long-term Debt - Affiliated | 0 | 0 | 0 | |||||
Long-term Debt | 1,323 | 1,323 | 1,153 | |||||
Total Long-term Debt Outstanding | 1,323 | 1,323 | 1,153 | |||||
Liabilities Held for Sale | 0 | 0 | 0 | |||||
AEP Transmission Holdco [Member] | Significant Reconciling Items [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | 61 | 34 | 171 | 86 | ||||
Generation And Marketing [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | 802 | 538 | [4] | 2,289 | 1,932 | [4] | ||
Revenues | 835 | 901 | 2,806 | 3,065 | ||||
Income from Continuing Operations | 91 | 117 | 360 | 378 | ||||
Income from Discontinued Operations, Net of Tax | 0 | 0 | 0 | 0 | ||||
NET INCOME (LOSS) | 91 | 117 | 360 | 378 | ||||
Balance Sheet Information | ||||||||
Total Property, Plant and Equipment | 7,474 | 7,474 | 8,394 | |||||
Accumulated Depreciation and Amortization | 3,390 | 3,390 | 3,603 | |||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 4,084 | 4,084 | 4,791 | |||||
Assets Held for Sale | 0 | 0 | 0 | |||||
Total Assets | 5,531 | 5,531 | 6,329 | |||||
Long-term Debt Due Within One Year - Affiliated | 0 | 0 | 86 | |||||
Long-term Debt Due Within One Year | 151 | 151 | 740 | |||||
Long-term Debt - Affiliated | 32 | 32 | 32 | |||||
Long-term Debt | 641 | 641 | 217 | |||||
Total Long-term Debt Outstanding | 824 | 824 | 1,075 | |||||
Liabilities Held for Sale | 0 | 0 | 0 | |||||
Generation And Marketing [Member] | Significant Reconciling Items [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | 33 | 363 | [4] | 517 | 1,133 | [4] | ||
AEP River Operations [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | 0 | 0 | 0 | 0 | ||||
Revenues | 0 | 0 | 0 | 0 | ||||
Income from Continuing Operations | (4) | 0 | (2) | 1 | ||||
Income from Discontinued Operations, Net of Tax | 8 | 11 | 18 | 16 | ||||
NET INCOME (LOSS) | 4 | 11 | 16 | 17 | ||||
Balance Sheet Information | ||||||||
Total Property, Plant and Equipment | 0 | 0 | 0 | |||||
Accumulated Depreciation and Amortization | 0 | 0 | 0 | |||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 0 | 0 | 0 | |||||
Assets Held for Sale | 608 | 608 | 625 | |||||
Total Assets | [5] | 772 | 772 | 749 | ||||
Long-term Debt Due Within One Year - Affiliated | 0 | 0 | 0 | |||||
Long-term Debt Due Within One Year | 0 | 0 | 0 | |||||
Long-term Debt - Affiliated | 0 | 0 | 0 | |||||
Long-term Debt | 0 | 0 | 0 | |||||
Total Long-term Debt Outstanding | 0 | 0 | 0 | |||||
Liabilities Held for Sale | 474 | 474 | 435 | |||||
AEP River Operations [Member] | Significant Reconciling Items [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | 0 | 0 | 0 | 0 | ||||
All Other [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | [6] | 3 | 7 | 16 | 19 | |||
Revenues | [6] | 24 | 26 | 74 | 74 | |||
Income from Continuing Operations | [6] | (9) | 11 | (13) | 4 | |||
Income from Discontinued Operations, Net of Tax | [6] | 0 | 0 | 0 | 0 | |||
NET INCOME (LOSS) | [6] | (9) | 11 | (13) | 4 | |||
Balance Sheet Information | ||||||||
Total Property, Plant and Equipment | [6] | 349 | 349 | 343 | ||||
Accumulated Depreciation and Amortization | [6] | 178 | 178 | 188 | ||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | [6] | 171 | 171 | 155 | ||||
Assets Held for Sale | [6] | 0 | 0 | 0 | ||||
Total Assets | [6] | 21,810 | 21,810 | 21,081 | ||||
Long-term Debt Due Within One Year - Affiliated | [6] | 0 | 0 | 0 | ||||
Long-term Debt Due Within One Year | [6] | 2 | 2 | 3 | ||||
Long-term Debt - Affiliated | [6] | 0 | 0 | 0 | ||||
Long-term Debt | [6] | 848 | 848 | 841 | ||||
Total Long-term Debt Outstanding | [6] | 850 | 850 | 844 | ||||
Liabilities Held for Sale | [6] | 0 | 0 | $ 0 | ||||
All Other [Member] | Significant Reconciling Items [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | [6] | 21 | 19 | 58 | 55 | |||
Consolidation, Eliminations [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | [7] | 0 | 0 | 0 | (51) | |||
Revenues | (175) | (502) | (965) | (1,588) | ||||
Income from Continuing Operations | 0 | 0 | 0 | 0 | ||||
Income from Discontinued Operations, Net of Tax | 0 | 0 | 0 | 0 | ||||
Consolidation, Eliminations [Member] | Reconciling Adjustments [Member] | ||||||||
Reportable Segment Information | ||||||||
Sales Revenue, Net | $ (175) | $ (502) | $ (965) | $ (1,537) | ||||
[1] | Amounts include debt related to AEPRO. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. | |||||||
[2] | Includes eliminations due to an intercompany capital lease. | |||||||
[3] | Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies. | |||||||
[4] | Includes the impact of corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. | |||||||
[5] | Amounts include intercompany advances to affiliates and intercompany accounts receivable that will be settled prior to or upon the close of the sale of AEPRO. | |||||||
[6] | Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. | |||||||
[7] | Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. |
Derivatives and Hedging (Detail
Derivatives and Hedging (Details) gal in Thousands, T in Thousands, MWh in Thousands, MMBTU in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||
Sep. 30, 2015USD ($)MWhMMBTUTgal | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($)MWhMMBTUTgal | Sep. 30, 2014USD ($) | Dec. 31, 2014USD ($)MWhMMBTUTgal | |||||
Cash Collateral Netting | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | $ 4,000 | $ 4,000 | $ 4,000 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 47,000 | 47,000 | 35,000 | ||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 143,000 | 143,000 | 178,000 | ||||||
Long-term Risk Management Assets | 353,000 | 353,000 | 294,000 | ||||||
Total Assets | 496,000 | 496,000 | 472,000 | ||||||
Current Risk Management Liabilities | 75,000 | 75,000 | 92,000 | ||||||
Long-term Risk Management Liabilities | 201,000 | 201,000 | 131,000 | ||||||
Total Liabilities | 276,000 | 276,000 | 223,000 | ||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (20,000) | $ 15,000 | 100,000 | $ 203,000 | |||||
Gain (Loss) on Hedging Instruments | |||||||||
Gain (Loss) on Fair Value Hedging Instruments | 4,000 | (2,000) | 7,000 | 2,000 | |||||
Gain (Loss) on Fair Value Portion of Long Term Debt | (4,000) | 2,000 | (7,000) | (2,000) | |||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [1] | 7,000 | 7,000 | 16,000 | |||||
Hedging Liabilities | [1] | 25,000 | 25,000 | 15,000 | |||||
AOCI Gain (Loss) Net of Tax | (29,000) | (29,000) | (18,000) | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | $ 0 | 2,000 | |||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 87 months | ||||||||
Collateral Triggering Events [Abstract] | |||||||||
Fair Value of Contracts with Credit Downgrade Triggers | 0 | $ 0 | 0 | ||||||
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement | 0 | 0 | 0 | ||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs | 35,000 | 35,000 | 36,000 | ||||||
Amount of Collateral Attributable to Other Contracts | [2] | 299,000 | 299,000 | 281,000 | |||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements | 307,000 | 307,000 | 235,000 | ||||||
Amount of Cash Collateral Posted | 10,000 | 10,000 | 9,000 | ||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 251,000 | 251,000 | 178,000 | ||||||
Derivatives and Hedging (Textuals) [Abstract] | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 4,000 | 4,000 | 4,000 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 47,000 | $ 47,000 | 35,000 | ||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 87 months | ||||||||
Appalachian Power Co [Member] | |||||||||
Cash Collateral Netting | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | $ 0 | 68 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 1,688 | 1,688 | 98 | ||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 25,970 | 25,970 | 23,792 | ||||||
Long-term Risk Management Assets | 2,035 | 2,035 | 4,891 | ||||||
Current Risk Management Liabilities | 6,902 | 6,902 | 11,017 | ||||||
Long-term Risk Management Liabilities | 973 | 973 | 2,057 | ||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 5,424 | (4,946) | $ 37,015 | 47,139 | |||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 0 months | ||||||||
Collateral Triggering Events [Abstract] | |||||||||
Fair Value of Contracts with Credit Downgrade Triggers | 0 | $ 0 | 0 | ||||||
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement | 0 | 0 | 0 | ||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs | 2,913 | 2,913 | 6,339 | ||||||
Amount of Collateral Attributable to Other Contracts | 97 | 97 | 74 | ||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements | 5,310 | 5,310 | 9,043 | ||||||
Amount of Cash Collateral Posted | 0 | 0 | 0 | ||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 5,288 | 5,288 | 9,012 | ||||||
Derivatives and Hedging (Textuals) [Abstract] | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | 0 | 68 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 1,688 | $ 1,688 | 98 | ||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 0 months | ||||||||
Indiana Michigan Power Co [Member] | |||||||||
Cash Collateral Netting | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | $ 0 | 163 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 333 | 333 | 47 | ||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 8,574 | 8,574 | 22,328 | ||||||
Long-term Risk Management Assets | 1,338 | 1,338 | 3,317 | ||||||
Current Risk Management Liabilities | 4,615 | 4,615 | 5,223 | ||||||
Long-term Risk Management Liabilities | 1,248 | 1,248 | 1,395 | ||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 853 | 2,145 | $ 10,745 | 36,213 | |||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 0 months | ||||||||
Collateral Triggering Events [Abstract] | |||||||||
Fair Value of Contracts with Credit Downgrade Triggers | 0 | $ 0 | 0 | ||||||
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement | 0 | 0 | 0 | ||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs | 1,976 | 1,976 | 4,299 | ||||||
Amount of Collateral Attributable to Other Contracts | 66 | 66 | 47 | ||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements | 3,601 | 3,601 | 6,134 | ||||||
Amount of Cash Collateral Posted | 0 | 0 | 0 | ||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 3,586 | 3,586 | 6,113 | ||||||
Derivatives and Hedging (Textuals) [Abstract] | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | 0 | 163 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 333 | $ 333 | 47 | ||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 0 months | ||||||||
Ohio Power Co [Member] | |||||||||
Cash Collateral Netting | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | $ 0 | 0 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 500 | 500 | 102 | ||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 0 | 0 | 7,242 | ||||||
Long-term Risk Management Assets | 23,265 | 23,265 | 45,102 | ||||||
Current Risk Management Liabilities | 2,823 | 2,823 | 1,943 | ||||||
Long-term Risk Management Liabilities | 4,871 | 4,871 | 3,013 | ||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (23,436) | (2,366) | $ (26,517) | 39,193 | |||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 0 months | ||||||||
Collateral Triggering Events [Abstract] | |||||||||
Fair Value of Contracts with Credit Downgrade Triggers | 0 | $ 0 | 0 | ||||||
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement | 0 | 0 | 0 | ||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs | 0 | 0 | 0 | ||||||
Amount of Collateral Attributable to Other Contracts | 0 | 0 | 0 | ||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements | 0 | 0 | 0 | ||||||
Amount of Cash Collateral Posted | 0 | 0 | 0 | ||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 0 | 0 | 0 | ||||||
Derivatives and Hedging (Textuals) [Abstract] | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | 0 | 0 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 500 | $ 500 | 102 | ||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 0 months | ||||||||
Public Service Co Of Oklahoma [Member] | |||||||||
Cash Collateral Netting | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | $ 0 | 0 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 280 | 280 | 54 | ||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 1,035 | 1,035 | 0 | ||||||
Current Risk Management Liabilities | 70 | 70 | 918 | ||||||
Long-term Risk Management Liabilities | 8 | 8 | 0 | ||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (894) | 252 | $ 5,152 | 701 | |||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 0 months | ||||||||
Collateral Triggering Events [Abstract] | |||||||||
Fair Value of Contracts with Credit Downgrade Triggers | 0 | $ 0 | 0 | ||||||
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement | 0 | 0 | 0 | ||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs | 2,692 | 2,692 | 693 | ||||||
Amount of Collateral Attributable to Other Contracts | 3,247 | 3,247 | 4,111 | ||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements | 0 | 0 | 0 | ||||||
Amount of Cash Collateral Posted | 0 | 0 | 0 | ||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 0 | 0 | 0 | ||||||
Derivatives and Hedging (Textuals) [Abstract] | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | 0 | 0 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 280 | $ 280 | 54 | ||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 0 months | ||||||||
Southwestern Electric Power Co [Member] | |||||||||
Cash Collateral Netting | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | $ 0 | 0 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 319 | 319 | 62 | ||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 1,280 | 1,280 | 31 | ||||||
Current Risk Management Liabilities | 1,302 | 1,302 | 1,082 | ||||||
Long-term Risk Management Liabilities | 757 | 757 | 0 | ||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 1,103 | (390) | $ 12,593 | (148) | |||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 0 months | ||||||||
Collateral Triggering Events [Abstract] | |||||||||
Fair Value of Contracts with Credit Downgrade Triggers | 0 | $ 0 | 0 | ||||||
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement | 0 | 0 | 0 | ||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs | 3,328 | 3,328 | 877 | ||||||
Amount of Collateral Attributable to Other Contracts | 58 | 58 | 166 | ||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements | 0 | 0 | 0 | ||||||
Amount of Cash Collateral Posted | 0 | 0 | 0 | ||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 0 | 0 | 0 | ||||||
Derivatives and Hedging (Textuals) [Abstract] | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | 0 | 0 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 319 | $ 319 | 62 | ||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 0 months | ||||||||
Risk Management Contracts [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Total Assets | [3] | 487,000 | [4] | $ 487,000 | [4] | 453,000 | [5] | ||
Total Liabilities | [3] | 250,000 | [4] | 250,000 | [4] | 199,000 | [5] | ||
Risk Management Contracts [Member] | Appalachian Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Total Assets | [6],[7] | 29,385 | 29,385 | 28,683 | |||||
Total Liabilities | [6],[7] | 7,875 | 7,875 | 13,074 | |||||
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Total Assets | [6],[7] | 11,965 | 11,965 | 25,645 | |||||
Total Liabilities | [6],[7] | 5,863 | 5,863 | 6,618 | |||||
Risk Management Contracts [Member] | Ohio Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Total Assets | [6],[7] | 23,265 | 23,265 | 52,344 | |||||
Total Liabilities | [6],[7] | 7,694 | 7,694 | 4,956 | |||||
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Total Assets | [6],[7] | 1,035 | 1,035 | 0 | |||||
Total Liabilities | [6],[7] | 78 | 78 | 918 | |||||
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Total Assets | [6],[7] | 1,280 | 1,280 | 31 | |||||
Total Liabilities | [6],[7] | 2,059 | 2,059 | 1,082 | |||||
Commodity [Member] | |||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [1] | 7,000 | 7,000 | 16,000 | |||||
Hedging Liabilities | [1] | 24,000 | 24,000 | 14,000 | |||||
AOCI Gain (Loss) Net of Tax | (11,000) | (11,000) | 1,000 | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 1,000 | 4,000 | |||||||
Derivatives and Hedging (Textuals) [Abstract] | |||||||||
Cross Default Provisions Maximum Third Party Obligation Amount | 50,000 | 50,000 | 50,000 | ||||||
Commodity [Member] | Appalachian Power Co [Member] | |||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [8] | 0 | 0 | 0 | |||||
Hedging Liabilities | [8] | 0 | 0 | 0 | |||||
AOCI Gain (Loss) Net of Tax | 0 | 0 | 0 | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 0 | 0 | |||||||
Commodity [Member] | Indiana Michigan Power Co [Member] | |||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [8] | 0 | 0 | 0 | |||||
Hedging Liabilities | [8] | 0 | 0 | 0 | |||||
AOCI Gain (Loss) Net of Tax | 0 | 0 | 0 | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 0 | 0 | |||||||
Commodity [Member] | Ohio Power Co [Member] | |||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [8] | 0 | 0 | 0 | |||||
Hedging Liabilities | [8] | 0 | 0 | 0 | |||||
AOCI Gain (Loss) Net of Tax | 0 | 0 | 0 | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 0 | 0 | |||||||
Commodity [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [8] | 0 | 0 | 0 | |||||
Hedging Liabilities | [8] | 0 | 0 | 0 | |||||
AOCI Gain (Loss) Net of Tax | 0 | 0 | 0 | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 0 | 0 | |||||||
Commodity [Member] | Southwestern Electric Power Co [Member] | |||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [8] | 0 | 0 | 0 | |||||
Hedging Liabilities | [8] | 0 | 0 | 0 | |||||
AOCI Gain (Loss) Net of Tax | 0 | 0 | 0 | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 0 | 0 | |||||||
Commodity [Member] | Risk Management Contracts [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [9] | 311,000 | 311,000 | 392,000 | |||||
Long-term Risk Management Assets | [9] | 443,000 | 443,000 | 367,000 | |||||
Total Assets | [9] | 754,000 | 754,000 | 759,000 | |||||
Current Risk Management Liabilities | [9] | 267,000 | 267,000 | 329,000 | |||||
Long-term Risk Management Liabilities | [9] | 293,000 | 293,000 | 208,000 | |||||
Total Liabilities | [9] | 560,000 | 560,000 | 537,000 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [9] | 194,000 | 194,000 | 222,000 | |||||
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 34,278 | 34,278 | 32,903 | |||||
Long-term Risk Management Assets | [10] | 2,485 | 2,485 | 5,159 | |||||
Total Assets | [10] | 36,763 | 36,763 | 38,062 | |||||
Current Risk Management Liabilities | [10] | 15,345 | 15,345 | 20,161 | |||||
Long-term Risk Management Liabilities | [10] | 1,596 | 1,596 | 2,322 | |||||
Total Liabilities | [10] | 16,941 | 16,941 | 22,483 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 19,822 | 19,822 | 15,579 | |||||
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 16,675 | 16,675 | 28,545 | |||||
Long-term Risk Management Assets | [10] | 1,619 | 1,619 | 3,499 | |||||
Total Assets | [10] | 18,294 | 18,294 | 32,044 | |||||
Current Risk Management Liabilities | [10] | 10,901 | 10,901 | 11,326 | |||||
Long-term Risk Management Liabilities | [10] | 1,624 | 1,624 | 1,575 | |||||
Total Liabilities | [10] | 12,525 | 12,525 | 12,901 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 5,769 | 5,769 | 19,143 | |||||
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 0 | 0 | 7,242 | |||||
Long-term Risk Management Assets | [10] | 23,265 | 23,265 | 45,102 | |||||
Total Assets | [10] | 23,265 | 23,265 | 52,344 | |||||
Current Risk Management Liabilities | [10] | 3,271 | 3,271 | 2,045 | |||||
Long-term Risk Management Liabilities | [10] | 4,923 | 4,923 | 3,013 | |||||
Total Liabilities | [10] | 8,194 | 8,194 | 5,058 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 15,071 | 15,071 | 47,286 | |||||
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 1,166 | 1,166 | 360 | |||||
Long-term Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Total Assets | [10] | 1,166 | 1,166 | 360 | |||||
Current Risk Management Liabilities | [10] | 454 | 454 | 1,332 | |||||
Long-term Risk Management Liabilities | [10] | 35 | 35 | 0 | |||||
Total Liabilities | [10] | 489 | 489 | 1,332 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 677 | 677 | (972) | |||||
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 1,442 | 1,442 | 471 | |||||
Long-term Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Total Assets | [10] | 1,442 | 1,442 | 471 | |||||
Current Risk Management Liabilities | [10] | 1,752 | 1,752 | 1,584 | |||||
Long-term Risk Management Liabilities | [10] | 788 | 788 | 0 | |||||
Total Liabilities | [10] | 2,540 | 2,540 | 1,584 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | (1,098) | (1,098) | (1,113) | |||||
Commodity [Member] | Hedging Contracts [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [9] | 9,000 | 9,000 | 30,000 | |||||
Long-term Risk Management Assets | [9] | 3,000 | 3,000 | 3,000 | |||||
Total Assets | [9] | 12,000 | 12,000 | 33,000 | |||||
Current Risk Management Liabilities | [9] | 7,000 | 7,000 | 23,000 | |||||
Long-term Risk Management Liabilities | [9] | 22,000 | 22,000 | 8,000 | |||||
Total Liabilities | [9] | 29,000 | 29,000 | 31,000 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [9] | (17,000) | (17,000) | 2,000 | |||||
Commodity [Member] | Hedging Contracts [Member] | Appalachian Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Total Assets | [10] | 0 | 0 | 0 | |||||
Current Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Total Liabilities | [10] | 0 | 0 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 0 | 0 | 0 | |||||
Commodity [Member] | Hedging Contracts [Member] | Indiana Michigan Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Total Assets | [10] | 0 | 0 | 0 | |||||
Current Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Total Liabilities | [10] | 0 | 0 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 0 | 0 | 0 | |||||
Commodity [Member] | Hedging Contracts [Member] | Ohio Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Total Assets | [10] | 0 | 0 | 0 | |||||
Current Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Total Liabilities | [10] | 0 | 0 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 0 | 0 | 0 | |||||
Commodity [Member] | Hedging Contracts [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Total Assets | [10] | 0 | 0 | 0 | |||||
Current Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Total Liabilities | [10] | 0 | 0 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 0 | 0 | 0 | |||||
Commodity [Member] | Hedging Contracts [Member] | Southwestern Electric Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Total Assets | [10] | 0 | 0 | 0 | |||||
Current Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Total Liabilities | [10] | 0 | 0 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 0 | 0 | 0 | |||||
Interest Rate and Foreign Currency [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 560,000 | 560,000 | 815,000 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [1] | 0 | 0 | 0 | |||||
Hedging Liabilities | [1] | 1,000 | 1,000 | 1,000 | |||||
AOCI Gain (Loss) Net of Tax | (18,000) | (18,000) | (19,000) | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | (1,000) | (2,000) | |||||||
Interest Rate and Foreign Currency [Member] | Appalachian Power Co [Member] | |||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [8] | 0 | 0 | 0 | |||||
Hedging Liabilities | [8] | 0 | 0 | 0 | |||||
AOCI Gain (Loss) Net of Tax | 3,805 | 3,805 | 3,896 | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 734 | 275 | |||||||
Interest Rate and Foreign Currency [Member] | Indiana Michigan Power Co [Member] | |||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [8] | 0 | 0 | 0 | |||||
Hedging Liabilities | [8] | 0 | 0 | 0 | |||||
AOCI Gain (Loss) Net of Tax | (13,604) | (13,604) | (14,406) | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | (1,277) | (1,090) | |||||||
Interest Rate and Foreign Currency [Member] | Ohio Power Co [Member] | |||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [8] | 0 | 0 | 0 | |||||
Hedging Liabilities | [8] | 0 | 0 | 0 | |||||
AOCI Gain (Loss) Net of Tax | 4,572 | 4,572 | 5,602 | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 1,282 | 1,372 | |||||||
Interest Rate and Foreign Currency [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [8] | 0 | 0 | 0 | |||||
Hedging Liabilities | [8] | 0 | 0 | 0 | |||||
AOCI Gain (Loss) Net of Tax | 4,374 | 4,374 | 4,943 | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 771 | 759 | |||||||
Interest Rate and Foreign Currency [Member] | Southwestern Electric Power Co [Member] | |||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [8] | 0 | 0 | 0 | |||||
Hedging Liabilities | [8] | 0 | 0 | 0 | |||||
AOCI Gain (Loss) Net of Tax | (9,470) | (9,470) | (11,036) | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | (1,728) | (1,998) | |||||||
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [9] | 2,000 | 2,000 | 3,000 | |||||
Long-term Risk Management Assets | [9] | 0 | 0 | 0 | |||||
Total Assets | [9] | 2,000 | 2,000 | 3,000 | |||||
Current Risk Management Liabilities | [9] | 1,000 | 1,000 | 1,000 | |||||
Long-term Risk Management Liabilities | [9] | 1,000 | 1,000 | 9,000 | |||||
Total Liabilities | [9] | 2,000 | 2,000 | 10,000 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [9] | 0 | 0 | (7,000) | |||||
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Appalachian Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Total Assets | [10] | 0 | 0 | 0 | |||||
Current Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Total Liabilities | [10] | 0 | 0 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 0 | 0 | 0 | |||||
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Indiana Michigan Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Total Assets | [10] | 0 | 0 | 0 | |||||
Current Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Total Liabilities | [10] | 0 | 0 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 0 | 0 | 0 | |||||
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Ohio Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Total Assets | [10] | 0 | 0 | 0 | |||||
Current Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Total Liabilities | [10] | 0 | 0 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 0 | 0 | 0 | |||||
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Total Assets | [10] | 0 | 0 | 0 | |||||
Current Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Total Liabilities | [10] | 0 | 0 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 0 | 0 | 0 | |||||
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Southwestern Electric Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Total Assets | [10] | 0 | 0 | 0 | |||||
Current Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Long-term Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Total Liabilities | [10] | 0 | 0 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [10] | 0 | 0 | 0 | |||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 322,000 | 322,000 | 425,000 | ||||||
Long-term Risk Management Assets | 446,000 | 446,000 | 370,000 | ||||||
Total Assets | 768,000 | 768,000 | 795,000 | ||||||
Current Risk Management Liabilities | 275,000 | 275,000 | 353,000 | ||||||
Long-term Risk Management Liabilities | 316,000 | 316,000 | 225,000 | ||||||
Total Liabilities | 591,000 | 591,000 | 578,000 | ||||||
Total MTM Derivative Contract Net Assets (Liabilities) | 177,000 | 177,000 | 217,000 | ||||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Appalachian Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 34,278 | 34,278 | 32,903 | ||||||
Long-term Risk Management Assets | 2,485 | 2,485 | 5,159 | ||||||
Total Assets | 36,763 | 36,763 | 38,062 | ||||||
Current Risk Management Liabilities | 15,345 | 15,345 | 20,161 | ||||||
Long-term Risk Management Liabilities | 1,596 | 1,596 | 2,322 | ||||||
Total Liabilities | 16,941 | 16,941 | 22,483 | ||||||
Total MTM Derivative Contract Net Assets (Liabilities) | 19,822 | 19,822 | 15,579 | ||||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Indiana Michigan Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 16,675 | 16,675 | 28,545 | ||||||
Long-term Risk Management Assets | 1,619 | 1,619 | 3,499 | ||||||
Total Assets | 18,294 | 18,294 | 32,044 | ||||||
Current Risk Management Liabilities | 10,901 | 10,901 | 11,326 | ||||||
Long-term Risk Management Liabilities | 1,624 | 1,624 | 1,575 | ||||||
Total Liabilities | 12,525 | 12,525 | 12,901 | ||||||
Total MTM Derivative Contract Net Assets (Liabilities) | 5,769 | 5,769 | 19,143 | ||||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Ohio Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 0 | 0 | 7,242 | ||||||
Long-term Risk Management Assets | 23,265 | 23,265 | 45,102 | ||||||
Total Assets | 23,265 | 23,265 | 52,344 | ||||||
Current Risk Management Liabilities | 3,271 | 3,271 | 2,045 | ||||||
Long-term Risk Management Liabilities | 4,923 | 4,923 | 3,013 | ||||||
Total Liabilities | 8,194 | 8,194 | 5,058 | ||||||
Total MTM Derivative Contract Net Assets (Liabilities) | 15,071 | 15,071 | 47,286 | ||||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 1,166 | 1,166 | 360 | ||||||
Long-term Risk Management Assets | 0 | 0 | 0 | ||||||
Total Assets | 1,166 | 1,166 | 360 | ||||||
Current Risk Management Liabilities | 454 | 454 | 1,332 | ||||||
Long-term Risk Management Liabilities | 35 | 35 | 0 | ||||||
Total Liabilities | 489 | 489 | 1,332 | ||||||
Total MTM Derivative Contract Net Assets (Liabilities) | 677 | 677 | (972) | ||||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Southwestern Electric Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 1,442 | 1,442 | 471 | ||||||
Long-term Risk Management Assets | 0 | 0 | 0 | ||||||
Total Assets | 1,442 | 1,442 | 471 | ||||||
Current Risk Management Liabilities | 1,752 | 1,752 | 1,584 | ||||||
Long-term Risk Management Liabilities | 788 | 788 | 0 | ||||||
Total Liabilities | 2,540 | 2,540 | 1,584 | ||||||
Total MTM Derivative Contract Net Assets (Liabilities) | (1,098) | (1,098) | (1,113) | ||||||
Gross Amounts Offset in the Statement of Financial Position [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [11] | (179,000) | (179,000) | (247,000) | |||||
Long-term Risk Management Assets | [11] | (93,000) | (93,000) | (76,000) | |||||
Total Assets | [11] | (272,000) | (272,000) | (323,000) | |||||
Current Risk Management Liabilities | [11] | (200,000) | (200,000) | (261,000) | |||||
Long-term Risk Management Liabilities | [11] | (115,000) | (115,000) | (94,000) | |||||
Total Liabilities | [11] | (315,000) | (315,000) | (355,000) | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [11] | 43,000 | 43,000 | 32,000 | |||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [12] | (6,928) | (6,928) | (9,111) | |||||
Long-term Risk Management Assets | [12] | (450) | (450) | (268) | |||||
Total Assets | [12] | (7,378) | (7,378) | (9,379) | |||||
Current Risk Management Liabilities | [12] | (8,443) | (8,443) | (9,144) | |||||
Long-term Risk Management Liabilities | [12] | (623) | (623) | (265) | |||||
Total Liabilities | [12] | (9,066) | (9,066) | (9,409) | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [12] | 1,688 | 1,688 | 30 | |||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [12] | (6,048) | (6,048) | (6,217) | |||||
Long-term Risk Management Assets | [12] | (281) | (281) | (182) | |||||
Total Assets | [12] | (6,329) | (6,329) | (6,399) | |||||
Current Risk Management Liabilities | [12] | (6,286) | (6,286) | (6,103) | |||||
Long-term Risk Management Liabilities | [12] | (376) | (376) | (180) | |||||
Total Liabilities | [12] | (6,662) | (6,662) | (6,283) | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [12] | 333 | 333 | (116) | |||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [12] | 0 | 0 | 0 | |||||
Long-term Risk Management Assets | [12] | 0 | 0 | 0 | |||||
Total Assets | [12] | 0 | 0 | 0 | |||||
Current Risk Management Liabilities | [12] | (448) | (448) | (102) | |||||
Long-term Risk Management Liabilities | [12] | (52) | (52) | 0 | |||||
Total Liabilities | [12] | (500) | (500) | (102) | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [12] | 500 | 500 | 102 | |||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [12] | (131) | (131) | (360) | |||||
Long-term Risk Management Assets | [12] | 0 | 0 | 0 | |||||
Total Assets | [12] | (131) | (131) | (360) | |||||
Current Risk Management Liabilities | [12] | (384) | (384) | (414) | |||||
Long-term Risk Management Liabilities | [12] | (27) | (27) | 0 | |||||
Total Liabilities | [12] | (411) | (411) | (414) | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [12] | 280 | 280 | 54 | |||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [12] | (162) | (162) | (440) | |||||
Long-term Risk Management Assets | [12] | 0 | 0 | 0 | |||||
Total Assets | [12] | (162) | (162) | (440) | |||||
Current Risk Management Liabilities | [12] | (450) | (450) | (502) | |||||
Long-term Risk Management Liabilities | [12] | (31) | (31) | 0 | |||||
Total Liabilities | [12] | (481) | (481) | (502) | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [12] | 319 | 319 | 62 | |||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [13] | 143,000 | 143,000 | 178,000 | |||||
Long-term Risk Management Assets | [13] | 353,000 | 353,000 | 294,000 | |||||
Total Assets | [13] | 496,000 | 496,000 | 472,000 | |||||
Current Risk Management Liabilities | [13] | 75,000 | 75,000 | 92,000 | |||||
Long-term Risk Management Liabilities | [13] | 201,000 | 201,000 | 131,000 | |||||
Total Liabilities | [13] | 276,000 | 276,000 | 223,000 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [13] | 220,000 | 220,000 | 249,000 | |||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Appalachian Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [14] | 27,350 | 27,350 | 23,792 | |||||
Long-term Risk Management Assets | [14] | 2,035 | 2,035 | 4,891 | |||||
Total Assets | [14] | 29,385 | 29,385 | 28,683 | |||||
Current Risk Management Liabilities | [14] | 6,902 | 6,902 | 11,017 | |||||
Long-term Risk Management Liabilities | [14] | 973 | 973 | 2,057 | |||||
Total Liabilities | [14] | 7,875 | 7,875 | 13,074 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [14] | 21,510 | 21,510 | 15,609 | |||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [14] | 10,627 | 10,627 | 22,328 | |||||
Long-term Risk Management Assets | [14] | 1,338 | 1,338 | 3,317 | |||||
Total Assets | [14] | 11,965 | 11,965 | 25,645 | |||||
Current Risk Management Liabilities | [14] | 4,615 | 4,615 | 5,223 | |||||
Long-term Risk Management Liabilities | [14] | 1,248 | 1,248 | 1,395 | |||||
Total Liabilities | [14] | 5,863 | 5,863 | 6,618 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [14] | 6,102 | 6,102 | 19,027 | |||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Ohio Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [14] | 0 | 0 | 7,242 | |||||
Long-term Risk Management Assets | [14] | 23,265 | 23,265 | 45,102 | |||||
Total Assets | [14] | 23,265 | 23,265 | 52,344 | |||||
Current Risk Management Liabilities | [14] | 2,823 | 2,823 | 1,943 | |||||
Long-term Risk Management Liabilities | [14] | 4,871 | 4,871 | 3,013 | |||||
Total Liabilities | [14] | 7,694 | 7,694 | 4,956 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [14] | 15,571 | 15,571 | 47,388 | |||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [14] | 1,035 | 1,035 | 0 | |||||
Long-term Risk Management Assets | [14] | 0 | 0 | 0 | |||||
Total Assets | [14] | 1,035 | 1,035 | 0 | |||||
Current Risk Management Liabilities | [14] | 70 | 70 | 918 | |||||
Long-term Risk Management Liabilities | [14] | 8 | 8 | 0 | |||||
Total Liabilities | [14] | 78 | 78 | 918 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [14] | 957 | 957 | (918) | |||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [14] | 1,280 | 1,280 | 31 | |||||
Long-term Risk Management Assets | [14] | 0 | 0 | 0 | |||||
Total Assets | [14] | 1,280 | 1,280 | 31 | |||||
Current Risk Management Liabilities | [14] | 1,302 | 1,302 | 1,082 | |||||
Long-term Risk Management Liabilities | [14] | 757 | 757 | 0 | |||||
Total Liabilities | [14] | 2,059 | 2,059 | 1,082 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [14] | $ (779) | $ (779) | $ (1,051) | |||||
Power [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MWh | 371,000 | 371,000 | 334,000 | ||||||
Power [Member] | Appalachian Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MWh | 62,306 | 62,306 | 32,479 | ||||||
Power [Member] | Indiana Michigan Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MWh | 30,345 | 30,345 | 23,774 | ||||||
Power [Member] | Ohio Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MWh | 13,470 | 13,470 | 20,334 | ||||||
Power [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MWh | 17,580 | 17,580 | 16,765 | ||||||
Power [Member] | Southwestern Electric Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MWh | 21,736 | 21,736 | 20,469 | ||||||
Coal [Member] | |||||||||
Commodity: | |||||||||
Derivative, Mass Notional Amount | T | 4,000 | 4,000 | 3,000 | ||||||
Coal [Member] | Appalachian Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Mass Notional Amount | T | 116 | 116 | 279 | ||||||
Coal [Member] | Indiana Michigan Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Mass Notional Amount | T | 1,468 | 1,468 | 500 | ||||||
Coal [Member] | Ohio Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Mass Notional Amount | T | 0 | 0 | 0 | ||||||
Coal [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Commodity: | |||||||||
Derivative, Mass Notional Amount | T | 0 | 0 | 0 | ||||||
Coal [Member] | Southwestern Electric Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Mass Notional Amount | T | 2,125 | 2,125 | 1,500 | ||||||
Natural Gas [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MMBTU | 46,000 | 46,000 | 106,000 | ||||||
Natural Gas [Member] | Appalachian Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MMBTU | 256 | 256 | 421 | ||||||
Natural Gas [Member] | Indiana Michigan Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MMBTU | 174 | 174 | 286 | ||||||
Natural Gas [Member] | Ohio Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MMBTU | 0 | 0 | 0 | ||||||
Natural Gas [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MMBTU | 0 | 0 | 0 | ||||||
Natural Gas [Member] | Southwestern Electric Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MMBTU | 0 | 0 | 0 | ||||||
Heating Oil and Gasoline [Member] | |||||||||
Commodity: | |||||||||
Derivative, Volume Notional Amount | gal | 9,000 | 9,000 | 6,000 | ||||||
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Volume Notional Amount | gal | 1,763 | 1,763 | 1,089 | ||||||
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Volume Notional Amount | gal | 836 | 836 | 521 | ||||||
Heating Oil and Gasoline [Member] | Ohio Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Volume Notional Amount | gal | 1,858 | 1,858 | 1,108 | ||||||
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Commodity: | |||||||||
Derivative, Volume Notional Amount | gal | 1,019 | 1,019 | 614 | ||||||
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Volume Notional Amount | gal | 1,166 | 1,166 | 699 | ||||||
Interest Rate Contract [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | $ 114,000 | $ 114,000 | $ 152,000 | ||||||
Interest Rate Contract [Member] | Appalachian Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 2,645 | 2,645 | 5,094 | ||||||
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 1,794 | 1,794 | 3,455 | ||||||
Interest Rate Contract [Member] | Ohio Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | 0 | ||||||
Interest Rate Contract [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | 0 | ||||||
Interest Rate Contract [Member] | Southwestern Electric Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | $ 0 | ||||||
Vertically Integrated Utilities Revenues [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 7,000 | 7,000 | 29,000 | |||||
Transmission and Distribution Utilities Revenues [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (1,000) | 0 | (1,000) | 0 | |||||
Generation & Marketing Revenues [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 1,000 | 21,000 | 60,000 | 69,000 | |||||
Electric Generation, Transmission and Distribution Revenues [Member] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (369) | 1,231 | 790 | 7,262 | |||||
Electric Generation, Transmission and Distribution Revenues [Member] | Indiana Michigan Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 350 | 2,988 | 3,591 | 10,467 | |||||
Electric Generation, Transmission and Distribution Revenues [Member] | Ohio Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (917) | 41 | (882) | 97 | |||||
Electric Generation, Transmission and Distribution Revenues [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (9) | 45 | 16 | 172 | |||||
Electric Generation, Transmission and Distribution Revenues [Member] | Southwestern Electric Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (7) | 74 | 19 | 18 | |||||
Sales to AEP Affiliates [Member] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 1,156 | 0 | 1,511 | 0 | |||||
Sales to AEP Affiliates [Member] | Indiana Michigan Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 3,336 | (196) | 4,341 | (717) | |||||
Sales to AEP Affiliates [Member] | Ohio Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | |||||
Sales to AEP Affiliates [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 196 | 0 | 717 | |||||
Sales to AEP Affiliates [Member] | Southwestern Electric Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | |||||
Other Operation Expense [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | (1,000) | 0 | |||||
Other Operation Expense [Member] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (88) | (287) | |||||||
Other Operation Expense [Member] | Indiana Michigan Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (63) | (221) | |||||||
Other Operation Expense [Member] | Ohio Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (128) | (389) | |||||||
Other Operation Expense [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (109) | (307) | |||||||
Other Operation Expense [Member] | Southwestern Electric Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (127) | (373) | |||||||
Maintenance Expense [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (1,000) | 0 | (2,000) | 0 | |||||
Maintenance Expense [Member] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (164) | (503) | |||||||
Maintenance Expense [Member] | Indiana Michigan Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (86) | (221) | |||||||
Maintenance Expense [Member] | Ohio Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (140) | (396) | |||||||
Maintenance Expense [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (88) | (248) | |||||||
Maintenance Expense [Member] | Southwestern Electric Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (88) | (265) | |||||||
Purchased Electricity for Resale [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 1,000 | 0 | 4,000 | 0 | |||||
Purchased Electricity for Resale [Member] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 831 | 1,571 | |||||||
Purchased Electricity for Resale [Member] | Indiana Michigan Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 15 | 347 | |||||||
Purchased Electricity for Resale [Member] | Ohio Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 30 | 30 | |||||||
Purchased Electricity for Resale [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | |||||||
Purchased Electricity for Resale [Member] | Southwestern Electric Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | |||||||
Regulatory Assets [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [15] | 0 | (6,000) | 0 | (6,000) | ||||
Regulatory Assets [Member] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [16] | 861 | (2,571) | 2,136 | (2,567) | ||||
Regulatory Assets [Member] | Indiana Michigan Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [16] | (981) | (471) | (1,213) | (471) | ||||
Regulatory Assets [Member] | Ohio Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [16] | 0 | (852) | 0 | (215) | ||||
Regulatory Assets [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [16] | (190) | (109) | 615 | (119) | ||||
Regulatory Assets [Member] | Southwestern Electric Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [16] | 188 | (284) | (1,234) | (285) | ||||
Regulatory Liabilities [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [15] | (20,000) | (7,000) | 33,000 | 111,000 | ||||
Regulatory Liabilities [Member] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [16] | 3,197 | (3,606) | 31,797 | 42,444 | ||||
Regulatory Liabilities [Member] | Indiana Michigan Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [16] | (1,718) | (176) | 4,121 | 26,934 | ||||
Regulatory Liabilities [Member] | Ohio Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [16] | (22,281) | (1,555) | (24,880) | 39,311 | ||||
Regulatory Liabilities [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [16] | (498) | 120 | 5,076 | (69) | ||||
Regulatory Liabilities [Member] | Southwestern Electric Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [16] | $ 1,137 | $ (180) | $ 14,446 | $ 119 | ||||
[1] | Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | ||||||||
[2] | Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contracts. | ||||||||
[3] | Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.'' | ||||||||
[4] | The September 30, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($4) million in 2015 and ($12) million in periods 2016-2018; Level 2 matures $5 million in 2015, $28 million in periods 2016-2018, $3 million in periods 2019-2020 and $2 million in periods 2021-2032; Level 3 matures $2 million in 2015, $63 million in periods 2016-2018, $25 million in periods 2019-2020 and $82 million in periods 2021-2032. Risk management commodity contracts are substantially comprised of power contracts. | ||||||||
[5] | The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. | ||||||||
[6] | Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” | ||||||||
[7] | Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | ||||||||
[8] | Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | ||||||||
[9] | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | ||||||||
[10] | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | ||||||||
[11] | Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | ||||||||
[12] | Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | ||||||||
[13] | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | ||||||||
[14] | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | ||||||||
[15] | Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||
[16] | Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Fair Value Long-term Debt, Othe
Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | ||
Book Values and Fair Values of Long - term Debt | ||||||
Total Long-term Debt Outstanding | $ 19,426,000 | $ 19,426,000 | $ 18,601,000 | |||
Long Term Debt, Fair Value | 21,257,000 | 21,257,000 | 21,075,000 | |||
Other Temporary Investments | ||||||
Cost | 305,000 | 305,000 | 374,000 | |||
Gross Unrealized Gains | 10,000 | 10,000 | 12,000 | |||
Gross Unrealized Losses | 0 | 0 | 0 | |||
Fair Value | 315,000 | 315,000 | 386,000 | |||
Debt and Equity Securities Within Other Temporary Investments [Abstract] | ||||||
Proceeds from Investment Sales | 0 | $ 0 | 0 | $ 0 | ||
Purchases of Investments | 10,000 | 0 | 10,000 | 1,000 | ||
Gross Realized Gains on Investment Sales | 0 | 0 | 0 | 0 | ||
Gross Realized Losses on Investment Sales | 0 | 0 | 0 | 0 | ||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 2,047,000 | 2,047,000 | 2,096,000 | |||
Gross Unrealized Gains | 566,000 | 566,000 | 649,000 | |||
Other-Than-Temporary Impairments | (83,000) | (83,000) | (85,000) | |||
Securities Activity Within Decommissioning and SNF Trusts [Abstract] | ||||||
Proceeds from Investment Sales | 921,000 | 263,000 | 1,437,000 | 746,000 | ||
Purchases of Investments | 938,000 | 281,000 | 1,479,000 | 790,000 | ||
Gross Realized Gains on Investment Sales | 15,000 | 8,000 | 34,000 | 25,000 | ||
Gross Realized Losses on Investment Sales | 13,000 | 1,000 | 23,000 | 10,000 | ||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 2,047,000 | 2,047,000 | 2,096,000 | |||
Fair Value Measurements (Textuals) [Abstract] | ||||||
Adjusted Cost of Debt Securities | 766,000 | 766,000 | 903,000 | |||
Adjusted Cost of Domestic Equity Securities | 551,000 | 551,000 | 524,000 | |||
Includes Debt Included In Liabilities Held For Sale [Member] | ||||||
Book Values and Fair Values of Long - term Debt | ||||||
Total Long-term Debt Outstanding | [1],[2] | 19,507,000 | 19,507,000 | 18,684,000 | ||
Appalachian Power Co [Member] | ||||||
Book Values and Fair Values of Long - term Debt | ||||||
Total Long-term Debt Outstanding | 3,955,295 | 3,955,295 | 3,980,274 | |||
Long Term Debt, Fair Value | 4,460,140 | 4,460,140 | 4,711,210 | |||
Indiana Michigan Power Co [Member] | ||||||
Book Values and Fair Values of Long - term Debt | ||||||
Total Long-term Debt Outstanding | 2,060,651 | 2,060,651 | 2,027,397 | |||
Long Term Debt, Fair Value | 2,241,930 | 2,241,930 | 2,255,124 | |||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 2,047,260 | 2,047,260 | 2,095,732 | |||
Gross Unrealized Gains | 565,889 | 565,889 | 649,132 | |||
Other-Than-Temporary Impairments | (83,938) | (83,938) | (85,495) | |||
Securities Activity Within Decommissioning and SNF Trusts [Abstract] | ||||||
Proceeds from Investment Sales | 921,552 | 263,738 | 1,437,336 | 746,272 | ||
Purchases of Investments | 938,438 | 280,626 | 1,479,149 | 789,461 | ||
Gross Realized Gains on Investment Sales | 15,030 | 7,617 | 33,840 | 24,835 | ||
Gross Realized Losses on Investment Sales | 13,167 | $ 1,739 | 22,823 | $ 10,447 | ||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 2,047,260 | 2,047,260 | 2,095,732 | |||
Fair Value Measurements (Textuals) [Abstract] | ||||||
Adjusted Cost of Debt Securities | 766,000 | 766,000 | 903,000 | |||
Adjusted Cost of Domestic Equity Securities | 551,000 | 551,000 | 524,000 | |||
Ohio Power Co [Member] | ||||||
Book Values and Fair Values of Long - term Debt | ||||||
Total Long-term Debt Outstanding | 2,166,050 | 2,166,050 | 2,297,123 | |||
Long Term Debt, Fair Value | 2,502,105 | 2,502,105 | 2,709,452 | |||
Public Service Co Of Oklahoma [Member] | ||||||
Book Values and Fair Values of Long - term Debt | ||||||
Total Long-term Debt Outstanding | 1,290,973 | 1,290,973 | 1,041,036 | |||
Long Term Debt, Fair Value | 1,424,300 | 1,424,300 | 1,216,205 | |||
Southwestern Electric Power Co [Member] | ||||||
Book Values and Fair Values of Long - term Debt | ||||||
Total Long-term Debt Outstanding | 2,283,966 | 2,283,966 | 2,140,437 | |||
Long Term Debt, Fair Value | 2,446,716 | 2,446,716 | 2,402,639 | |||
Cash [Member] | ||||||
Other Temporary Investments | ||||||
Cost | [3] | 201,000 | 201,000 | 280,000 | ||
Gross Unrealized Gains | [3] | 0 | 0 | 0 | ||
Gross Unrealized Losses | [3] | 0 | 0 | 0 | ||
Fair Value | [3],[4] | 201,000 | 201,000 | 280,000 | ||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | [5] | 164,000 | 164,000 | 20,000 | ||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | [5] | 164,000 | 164,000 | 20,000 | ||
Cash [Member] | Indiana Michigan Power Co [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | [6] | 164,353 | 164,353 | 19,966 | ||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | [6] | 164,353 | 164,353 | 19,966 | ||
Fixed Income Funds [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 816,000 | 816,000 | 953,000 | |||
Gross Unrealized Gains | 50,000 | 50,000 | 50,000 | |||
Other-Than-Temporary Impairments | (3,000) | (3,000) | (6,000) | |||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 816,000 | 816,000 | 953,000 | |||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 816,480 | 816,480 | 953,387 | |||
Gross Unrealized Gains | 49,683 | 49,683 | 50,344 | |||
Other-Than-Temporary Impairments | (3,658) | (3,658) | (6,353) | |||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 816,480 | 816,480 | 953,387 | |||
Mutual Funds Fixed Income [Member] | ||||||
Other Temporary Investments | ||||||
Cost | 90,000 | 90,000 | 81,000 | |||
Gross Unrealized Gains | 0 | 0 | 0 | |||
Gross Unrealized Losses | 0 | 0 | 0 | |||
Fair Value | 90,000 | 90,000 | 81,000 | |||
Domestic [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | [7] | 1,067,000 | 1,067,000 | 1,123,000 | ||
Gross Unrealized Gains | 516,000 | 516,000 | 599,000 | |||
Other-Than-Temporary Impairments | (80,000) | (80,000) | (79,000) | |||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | [7] | 1,067,000 | 1,067,000 | 1,123,000 | ||
Domestic [Member] | Indiana Michigan Power Co [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | [8] | 1,066,427 | 1,066,427 | 1,122,379 | ||
Gross Unrealized Gains | 516,206 | 516,206 | 598,788 | |||
Other-Than-Temporary Impairments | (80,280) | (80,280) | (79,142) | |||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | [8] | 1,066,427 | 1,066,427 | 1,122,379 | ||
Mutual Funds Equity [Member] | ||||||
Other Temporary Investments | ||||||
Cost | 14,000 | 14,000 | 13,000 | |||
Gross Unrealized Gains | 10,000 | 10,000 | 12,000 | |||
Gross Unrealized Losses | 0 | 0 | 0 | |||
Fair Value | [7] | 24,000 | 24,000 | 25,000 | ||
Cash and Cash Equivalents [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 164,000 | 164,000 | 20,000 | |||
Gross Unrealized Gains | 0 | 0 | 0 | |||
Other-Than-Temporary Impairments | 0 | 0 | 0 | |||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 164,000 | 164,000 | 20,000 | |||
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 164,353 | 164,353 | 19,966 | |||
Gross Unrealized Gains | 0 | 0 | 0 | |||
Other-Than-Temporary Impairments | 0 | 0 | 0 | |||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 164,353 | 164,353 | 19,966 | |||
US Government Agencies Debt Securities [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 704,000 | 704,000 | 697,000 | |||
Gross Unrealized Gains | 45,000 | 45,000 | 45,000 | |||
Other-Than-Temporary Impairments | (2,000) | (2,000) | (5,000) | |||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 704,000 | 704,000 | 697,000 | |||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 704,344 | 704,344 | 697,042 | |||
Gross Unrealized Gains | 45,005 | 45,005 | 44,615 | |||
Other-Than-Temporary Impairments | (2,291) | (2,291) | (5,016) | |||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 704,344 | 704,344 | 697,042 | |||
Corporate Debt [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 62,000 | 62,000 | 48,000 | |||
Gross Unrealized Gains | 4,000 | 4,000 | 4,000 | |||
Other-Than-Temporary Impairments | (1,000) | (1,000) | (1,000) | |||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 62,000 | 62,000 | 48,000 | |||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 62,118 | 62,118 | 47,792 | |||
Gross Unrealized Gains | 3,682 | 3,682 | 4,523 | |||
Other-Than-Temporary Impairments | (1,043) | (1,043) | (1,018) | |||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 62,118 | 62,118 | 47,792 | |||
State and Local Jurisdiction [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 50,000 | 50,000 | 208,000 | |||
Gross Unrealized Gains | 1,000 | 1,000 | 1,000 | |||
Other-Than-Temporary Impairments | 0 | 0 | 0 | |||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 50,000 | 50,000 | 208,000 | |||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 50,018 | 50,018 | 208,553 | |||
Gross Unrealized Gains | 996 | 996 | 1,206 | |||
Other-Than-Temporary Impairments | (324) | (324) | (319) | |||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 50,018 | 50,018 | $ 208,553 | |||
Within One Year [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 166,000 | 166,000 | ||||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 166,000 | 166,000 | ||||
Within One Year [Member] | Indiana Michigan Power Co [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 166,336 | 166,336 | ||||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 166,336 | 166,336 | ||||
One Year To Five Year [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 336,000 | 336,000 | ||||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 336,000 | 336,000 | ||||
One Year To Five Year [Member] | Indiana Michigan Power Co [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 335,823 | 335,823 | ||||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 335,823 | 335,823 | ||||
Five Year To Ten Year [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 140,000 | 140,000 | ||||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 140,000 | 140,000 | ||||
Five Year To Ten Year [Member] | Indiana Michigan Power Co [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 140,129 | 140,129 | ||||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 140,129 | 140,129 | ||||
After Ten Year [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 174,000 | 174,000 | ||||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | 174,000 | 174,000 | ||||
After Ten Year [Member] | Indiana Michigan Power Co [Member] | ||||||
Nuclear Trust Fund Investments [Abstract] | ||||||
Fair Value | 174,192 | 174,192 | ||||
Contractual Maturities, Fair Value of Debt Securities | ||||||
Contractual Maturities, Fair Value of Debt Securities | $ 174,192 | $ 174,192 | ||||
[1] | Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. | |||||
[2] | Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. | |||||
[3] | Primarily represents amounts held for the repayment of debt. | |||||
[4] | Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||
[5] | Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||
[6] | Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||
[7] | Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||
[8] | Amounts represent publicly traded equity securities and equity-based mutual funds. |
Fair Value Assets and Liabiliti
Fair Value Assets and Liabilities (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||
Sep. 30, 2015USD ($)$ / MWh | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($)$ / MWh | Sep. 30, 2014USD ($) | Dec. 31, 2014USD ($)$ / MWh | |||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [1] | $ 178,000 | $ 178,000 | $ 163,000 | |||||
Other Temporary Investments | 315,000 | 315,000 | 386,000 | ||||||
Risk Management Assets | |||||||||
Risk Management Assets | 496,000 | 496,000 | 472,000 | ||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 2,047,000 | 2,047,000 | 2,096,000 | ||||||
Total Assets | 3,036,000 | 3,036,000 | 3,117,000 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 276,000 | 276,000 | 223,000 | ||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | |||||||||
Beginning Balance | 203,000 | $ 132,000 | 151,000 | $ 117,000 | 117,000 | ||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | [2],[3] | 11,000 | (9,000) | 14,000 | 91,000 | ||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date | [2] | 6,000 | 10,000 | 54,000 | (3,000) | ||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | (2,000) | (3,000) | (4,000) | 12,000 | |||||
Purchases, Issuances and Settlements | [4] | (29,000) | (5,000) | (60,000) | (103,000) | ||||
Transfers into Level 3 | [5],[6] | 8,000 | (9,000) | 28,000 | (9,000) | ||||
Transfers out of Level 3 | [6],[7] | (5,000) | (1,000) | (17,000) | (8,000) | ||||
Changes in Fair Value Allocated to Regulated Jurisdictions | [8] | (25,000) | 14,000 | 1,000 | 32,000 | ||||
Ending Balance | 167,000 | 129,000 | $ 167,000 | 129,000 | $ 151,000 | ||||
Level 3 Quantitative Information [Abstract] | |||||||||
Counterparty Credit Risk | [9] | 4.81% | 3.03% | ||||||
Level 1 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [1] | 12,000 | $ 12,000 | $ 17,000 | |||||
Other Temporary Investments | 303,000 | 303,000 | 340,000 | ||||||
Risk Management Assets | |||||||||
Risk Management Assets | 17,000 | 17,000 | 37,000 | ||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 1,224,000 | 1,224,000 | 1,132,000 | ||||||
Total Assets | 1,556,000 | 1,556,000 | 1,526,000 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 33,000 | 33,000 | 65,000 | ||||||
Level 2 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [1] | 4,000 | 4,000 | 1,000 | |||||
Other Temporary Investments | 6,000 | 6,000 | 9,000 | ||||||
Risk Management Assets | |||||||||
Risk Management Assets | 489,000 | 489,000 | 561,000 | ||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 816,000 | 816,000 | 953,000 | ||||||
Total Assets | 1,315,000 | 1,315,000 | 1,524,000 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 463,000 | 463,000 | 467,000 | ||||||
Level 3 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [1] | 0 | 0 | 0 | |||||
Other Temporary Investments | 0 | 0 | 0 | ||||||
Risk Management Assets | |||||||||
Risk Management Assets | 249,000 | 249,000 | 190,000 | ||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Total Assets | 249,000 | 249,000 | 190,000 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 82,000 | 82,000 | 39,000 | ||||||
Fair Value Inputs Other [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [1] | 162,000 | 162,000 | 145,000 | |||||
Other Temporary Investments | 6,000 | 6,000 | 37,000 | ||||||
Risk Management Assets | |||||||||
Risk Management Assets | (259,000) | (259,000) | (316,000) | ||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 7,000 | 7,000 | 11,000 | ||||||
Total Assets | (84,000) | (84,000) | (123,000) | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | (302,000) | (302,000) | (348,000) | ||||||
2015 [Member] | Level 1 [Member] | |||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | |||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | (4,000) | (4,000) | (18,000) | ||||||
2015 [Member] | Level 2 [Member] | |||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | |||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 5,000 | 5,000 | 31,000 | ||||||
2015 [Member] | Level 3 [Member] | |||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | |||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 2,000 | 2,000 | 50,000 | ||||||
2016 - 2018 [Member] | Level 1 [Member] | |||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | |||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | (12,000) | (12,000) | (10,000) | ||||||
2016 - 2018 [Member] | Level 2 [Member] | |||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | |||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 28,000 | 28,000 | 52,000 | ||||||
2016 - 2018 [Member] | Level 3 [Member] | |||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | |||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 63,000 | 63,000 | 29,000 | ||||||
2019 - 2020 [Member] | Level 2 [Member] | |||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | |||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 3,000 | 3,000 | 12,000 | ||||||
2019 - 2020 [Member] | Level 3 [Member] | |||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | |||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 25,000 | 25,000 | 9,000 | ||||||
2021 - 2030 [Member] | Level 2 [Member] | |||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | |||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 1,000 | ||||||||
2021 - 2030 [Member] | Level 3 [Member] | |||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | |||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 66,000 | ||||||||
2021 - 2032 [Member] | Level 2 [Member] | |||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | |||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 2,000 | 2,000 | |||||||
2021 - 2032 [Member] | Level 3 [Member] | |||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | |||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 82,000 | 82,000 | |||||||
Risk Management Commodity Contracts [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [10] | 487,000 | [11] | 487,000 | [11] | 453,000 | [12] | ||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [10] | 250,000 | [11] | 250,000 | [11] | 199,000 | [12] | ||
Risk Management Commodity Contracts [Member] | Level 1 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [10] | 17,000 | [11] | 17,000 | [11] | 37,000 | [12] | ||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [10] | 33,000 | [11] | 33,000 | [11] | 65,000 | [12] | ||
Risk Management Commodity Contracts [Member] | Level 2 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [10] | 478,000 | [11] | 478,000 | [11] | 528,000 | [12] | ||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [10] | 440,000 | [11] | 440,000 | [11] | 432,000 | [12] | ||
Risk Management Commodity Contracts [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [10] | 248,000 | [11] | 248,000 | [11] | 190,000 | [12] | ||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [10] | 76,000 | [11] | 76,000 | [11] | 36,000 | [12] | ||
Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [10] | (256,000) | [11] | (256,000) | [11] | (302,000) | [12] | ||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [10] | (299,000) | [11] | (299,000) | [11] | (334,000) | [12] | ||
Energy Contracts [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | 226,000 | 226,000 | 157,000 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | $ 79,000 | $ 79,000 | $ 37,000 | ||||||
Level 3 Quantitative Information [Abstract] | |||||||||
Forward Price Range Low | $ / MWh | [13] | 13.03 | 13.03 | 11.37 | |||||
Forward Price Range High | $ / MWh | [13] | 165.93 | 165.93 | 159.92 | |||||
Weighted Average Market Price | $ / MWh | [13] | 36.37 | 36.37 | 57.18 | |||||
FTRs [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | $ 23,000 | $ 23,000 | $ 33,000 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | $ 3,000 | $ 3,000 | $ 2,000 | ||||||
Level 3 Quantitative Information [Abstract] | |||||||||
Forward Price Range Low | $ / MWh | [13] | (10.67) | (10.67) | (14.63) | |||||
Forward Price Range High | $ / MWh | [13] | 11.6 | 11.6 | 20.02 | |||||
Weighted Average Market Price | $ / MWh | [13] | 1.31 | 1.31 | 0.96 | |||||
Commodity Hedges [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [10] | $ 7,000 | $ 7,000 | $ 16,000 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [10] | 24,000 | 24,000 | 14,000 | |||||
Commodity Hedges [Member] | Level 1 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [10] | 0 | 0 | 0 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [10] | 0 | 0 | 0 | |||||
Commodity Hedges [Member] | Level 2 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [10] | 10,000 | 10,000 | 32,000 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [10] | 22,000 | 22,000 | 27,000 | |||||
Commodity Hedges [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [10] | 1,000 | 1,000 | 0 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [10] | 6,000 | 6,000 | 3,000 | |||||
Commodity Hedges [Member] | Fair Value Inputs Other [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [10] | (4,000) | (4,000) | (16,000) | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [10] | (4,000) | (4,000) | (16,000) | |||||
Interest Rate Foreign Currency Hedges [Member] | |||||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 1,000 | 1,000 | 1,000 | ||||||
Interest Rate Foreign Currency Hedges [Member] | Level 1 [Member] | |||||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 0 | 0 | 0 | ||||||
Interest Rate Foreign Currency Hedges [Member] | Level 2 [Member] | |||||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 1,000 | 1,000 | 1,000 | ||||||
Interest Rate Foreign Currency Hedges [Member] | Level 3 [Member] | |||||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 0 | 0 | 0 | ||||||
Interest Rate Foreign Currency Hedges [Member] | Fair Value Inputs Other [Member] | |||||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 0 | 0 | 0 | ||||||
Fair Value Hedges [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | 2,000 | 2,000 | 3,000 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 1,000 | 1,000 | 9,000 | ||||||
Fair Value Hedges [Member] | Level 1 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | 0 | 0 | 0 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 0 | 0 | 0 | ||||||
Fair Value Hedges [Member] | Level 2 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | 1,000 | 1,000 | 1,000 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 0 | 0 | 7,000 | ||||||
Fair Value Hedges [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | 0 | 0 | 0 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 0 | 0 | 0 | ||||||
Fair Value Hedges [Member] | Fair Value Inputs Other [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | 1,000 | 1,000 | 2,000 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 1,000 | 1,000 | 2,000 | ||||||
Appalachian Power Co [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 7,493 | 7,493 | 15,632 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 36,878 | 36,878 | 44,315 | ||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | |||||||||
Beginning Balance | 33,836 | [15] | 18,394 | 15,742 | [15] | 10,562 | 10,562 | ||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | [16],[17] | 5,065 | [15] | (5,629) | 1,757 | [15] | 29,467 | ||
Purchases, Issuances and Settlements | [18] | (13,965) | [15] | (1,560) | (16,124) | [15] | (32,213) | ||
Transfers into Level 3 | [19],[20] | (6) | (3,648) | ||||||
Transfers out of Level 3 | [20],[21] | (30) | 1,167 | [15] | (32) | ||||
Changes in Fair Value Allocated to Regulated Jurisdictions | [22] | (1,855) | [15] | 4,843 | 20,539 | [15] | 11,876 | ||
Ending Balance | 23,081 | [15] | 16,012 | 23,081 | [15] | 16,012 | 15,742 | [15] | |
Appalachian Power Co [Member] | Level 1 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 7,436 | 7,436 | 15,599 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 7,621 | 7,621 | 15,805 | ||||||
Appalachian Power Co [Member] | Level 2 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 0 | 0 | 0 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 12,785 | 12,785 | 20,197 | ||||||
Appalachian Power Co [Member] | Level 3 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 0 | 0 | 0 | |||||
Risk Management Assets | |||||||||
Risk Management Assets | 23,743 | 23,743 | 17,654 | ||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 23,743 | 23,743 | 17,654 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 662 | 662 | 1,912 | ||||||
Appalachian Power Co [Member] | Fair Value Inputs Other [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 57 | 57 | 33 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | (7,271) | (7,271) | (9,341) | ||||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 29,385 | 29,385 | 28,683 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 7,875 | 7,875 | 13,074 | |||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 185 | 185 | 206 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 198 | 198 | 227 | |||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 12,785 | 12,785 | 20,197 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 16,031 | 16,031 | 20,339 | |||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 23,743 | 23,743 | 17,654 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 662 | 662 | 1,912 | |||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | (7,328) | (7,328) | (9,374) | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | (9,016) | (9,016) | (9,404) | |||||
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | 8,724 | 8,724 | 5,801 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | $ 451 | $ 451 | $ 1,799 | ||||||
Level 3 Quantitative Information [Abstract] | |||||||||
Forward Price Range Low | $ / MWh | [25] | 13.03 | 13.03 | 13.43 | |||||
Forward Price Range High | $ / MWh | [25] | 48.17 | 48.17 | 123.02 | |||||
Weighted Average Market Price | $ / MWh | [25] | 34.76 | 34.76 | 52.47 | |||||
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | $ 15,019 | $ 15,019 | $ 11,853 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | $ 211 | $ 211 | $ 113 | ||||||
Level 3 Quantitative Information [Abstract] | |||||||||
Forward Price Range Low | $ / MWh | [25] | (5.95) | (5.95) | (14.63) | |||||
Forward Price Range High | $ / MWh | [25] | 11.6 | 11.6 | 20.02 | |||||
Weighted Average Market Price | $ / MWh | [25] | 1.53 | 1.53 | 1.01 | |||||
Indiana Michigan Power Co [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | $ 2,047,260 | $ 2,047,260 | $ 2,095,732 | ||||||
Total Assets | 2,059,225 | 2,059,225 | 2,121,377 | ||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | |||||||||
Beginning Balance | 11,844 | [15] | 12,923 | 14,704 | [15] | 7,164 | 7,164 | ||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | [16],[17] | 885 | [15] | (3,832) | (193) | [15] | 18,438 | ||
Purchases, Issuances and Settlements | [18] | (3,604) | [15] | (1,244) | (12,807) | [15] | (20,301) | ||
Transfers into Level 3 | [19],[20] | (4) | (2,475) | ||||||
Transfers out of Level 3 | [20],[21] | (20) | 792 | [15] | (22) | ||||
Changes in Fair Value Allocated to Regulated Jurisdictions | [22] | (2,749) | [15] | 4,319 | 3,880 | [15] | 9,338 | ||
Ending Balance | 6,376 | [15] | 12,142 | 6,376 | [15] | 12,142 | 14,704 | [15] | |
Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 1,223,836 | 1,223,836 | 1,131,797 | ||||||
Total Assets | 1,223,962 | 1,223,962 | 1,131,937 | ||||||
Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 816,480 | 816,480 | 953,387 | ||||||
Total Assets | 826,827 | 826,827 | 969,280 | ||||||
Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | 7,795 | 7,795 | 16,008 | ||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Total Assets | 7,795 | 7,795 | 16,008 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 1,419 | 1,419 | 1,304 | ||||||
Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 6,944 | 6,944 | 10,548 | ||||||
Total Assets | 641 | 641 | 4,152 | ||||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 11,965 | 11,965 | 25,645 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 5,863 | 5,863 | 6,618 | |||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 126 | 126 | 140 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 135 | 135 | 154 | |||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 10,347 | 10,347 | 15,893 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 10,945 | 10,945 | 11,440 | |||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 7,795 | 7,795 | 16,008 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 1,419 | 1,419 | 1,304 | |||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | (6,303) | (6,303) | (6,396) | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | (6,636) | (6,636) | (6,280) | |||||
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | 7,147 | 7,147 | 6,375 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | $ 295 | $ 295 | $ 1,219 | ||||||
Level 3 Quantitative Information [Abstract] | |||||||||
Forward Price Range Low | $ / MWh | [25] | 13.03 | 13.03 | 13.43 | |||||
Forward Price Range High | $ / MWh | [25] | 48.17 | 48.17 | 123.02 | |||||
Weighted Average Market Price | $ / MWh | [25] | 34.76 | 34.76 | 52.47 | |||||
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | $ 648 | $ 648 | $ 9,633 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | $ 1,124 | $ 1,124 | $ 85 | ||||||
Level 3 Quantitative Information [Abstract] | |||||||||
Forward Price Range Low | $ / MWh | [25] | (5.95) | (5.95) | (14.63) | |||||
Forward Price Range High | $ / MWh | [25] | 11.6 | 11.6 | 20.02 | |||||
Weighted Average Market Price | $ / MWh | [25] | 1.53 | 1.53 | 1.01 | |||||
Ohio Power Co [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | $ 16,204 | $ 16,204 | $ 28,696 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 39,469 | 39,469 | 81,040 | ||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | |||||||||
Beginning Balance | 37,657 | 9,300 | 48,402 | 2,920 | 2,920 | ||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | [16],[17] | (28) | (3,639) | 1,182 | 30,768 | ||||
Purchases, Issuances and Settlements | [18] | 348 | (637) | (7,906) | (33,688) | ||||
Transfers into Level 3 | [19],[20] | 0 | 0 | ||||||
Transfers out of Level 3 | [20],[21] | 0 | 0 | 0 | |||||
Changes in Fair Value Allocated to Regulated Jurisdictions | [22] | (22,267) | 2,865 | (25,968) | 7,889 | ||||
Ending Balance | 15,710 | 7,889 | 15,710 | 7,889 | 48,402 | ||||
Ohio Power Co [Member] | Level 1 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 16,195 | 16,195 | 408 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 16,195 | 16,195 | 408 | ||||||
Ohio Power Co [Member] | Level 2 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 0 | 0 | 0 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 0 | 0 | 0 | ||||||
Ohio Power Co [Member] | Level 3 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 0 | 0 | 0 | |||||
Risk Management Assets | |||||||||
Risk Management Assets | 52,343 | ||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 20,719 | 20,719 | 52,343 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | 3,941 | ||||||||
Ohio Power Co [Member] | Fair Value Inputs Other [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 9 | 9 | 28,288 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 2,555 | 2,555 | 28,289 | ||||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 23,265 | 23,265 | 52,344 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 7,694 | 7,694 | 4,956 | |||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 0 | 0 | 0 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 0 | 0 | 0 | |||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 0 | 0 | 0 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 639 | 639 | 1,116 | |||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 20,719 | 20,719 | 52,343 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 5,009 | 5,009 | 3,941 | |||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 2,546 | 2,546 | 1 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 2,046 | 2,046 | (101) | |||||
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | 20,719 | 20,719 | 45,101 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | $ 5,009 | $ 5,009 | $ 3,941 | ||||||
Level 3 Quantitative Information [Abstract] | |||||||||
Forward Price Range Low | $ / MWh | [25] | 35.71 | 35.71 | 48.25 | |||||
Forward Price Range High | $ / MWh | [25] | 165.93 | 165.93 | 159.92 | |||||
Weighted Average Market Price | $ / MWh | [25] | 85.99 | 85.99 | 84.04 | |||||
Ohio Power Co [Member] | FTRs [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | $ 7,242 | ||||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | $ 0 | ||||||||
Level 3 Quantitative Information [Abstract] | |||||||||
Forward Price Range Low | $ / MWh | [25] | (14.63) | |||||||
Forward Price Range High | $ / MWh | [25] | 20.02 | |||||||
Weighted Average Market Price | $ / MWh | [25] | 1.01 | |||||||
Public Service Co Of Oklahoma [Member] | |||||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | |||||||||
Beginning Balance | $ 1,699 | (3) | $ (377) | 0 | $ 0 | ||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | [16],[17] | (280) | 2 | (176) | 0 | ||||
Purchases, Issuances and Settlements | [18] | (176) | 0 | 553 | 0 | ||||
Transfers into Level 3 | [19],[20] | 0 | 0 | ||||||
Transfers out of Level 3 | [20],[21] | 0 | 0 | 0 | |||||
Changes in Fair Value Allocated to Regulated Jurisdictions | [22] | (208) | 335 | 1,035 | 334 | ||||
Ending Balance | 1,035 | 334 | 1,035 | 334 | (377) | ||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 1,035 | 1,035 | 0 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 78 | 78 | 918 | |||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 0 | 0 | 0 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 0 | 0 | 0 | |||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 0 | 0 | 0 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 358 | 358 | 595 | |||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 1,166 | 1,166 | 360 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 131 | 131 | 737 | |||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | (131) | (131) | (360) | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | (411) | (411) | (414) | |||||
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | 1,166 | 1,166 | 360 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | $ 131 | $ 131 | $ 737 | ||||||
Level 3 Quantitative Information [Abstract] | |||||||||
Forward Price Range Low | $ / MWh | [25] | (5.95) | (5.95) | (14.63) | |||||
Forward Price Range High | $ / MWh | [25] | 11.6 | 11.6 | 20.02 | |||||
Weighted Average Market Price | $ / MWh | [25] | 1.53 | 1.53 | 1.01 | |||||
Southwestern Electric Power Co [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | $ 14,258 | $ 14,258 | $ 14,356 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 15,538 | 15,538 | 14,387 | ||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | |||||||||
Beginning Balance | 2,039 | (3) | (460) | 0 | 0 | ||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | [16],[17] | 2,366 | 2 | 9,187 | 0 | ||||
Purchases, Issuances and Settlements | [18] | (2,912) | 0 | (8,727) | 0 | ||||
Transfers into Level 3 | [19],[20] | 0 | 0 | ||||||
Transfers out of Level 3 | [20],[21] | 0 | 0 | 0 | |||||
Changes in Fair Value Allocated to Regulated Jurisdictions | [22] | (213) | 409 | 1,280 | 408 | ||||
Ending Balance | 1,280 | $ 408 | 1,280 | $ 408 | (460) | ||||
Southwestern Electric Power Co [Member] | Level 1 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 11,688 | 11,688 | 12,660 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 11,688 | 11,688 | 12,660 | ||||||
Southwestern Electric Power Co [Member] | Level 2 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 0 | 0 | 0 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 0 | 0 | 31 | ||||||
Southwestern Electric Power Co [Member] | Level 3 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 0 | 0 | 0 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 1,442 | 1,442 | 439 | ||||||
Southwestern Electric Power Co [Member] | Fair Value Inputs Other [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Cash and Cash Equivalents | [14] | 2,570 | 2,570 | 1,696 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Total Assets | 2,408 | 2,408 | 1,257 | ||||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 1,280 | 1,280 | 31 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 2,059 | 2,059 | 1,082 | |||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 0 | 0 | 0 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 0 | 0 | 0 | |||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 0 | 0 | 31 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 2,378 | 2,378 | 684 | |||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | 1,442 | 1,442 | 439 | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | 162 | 162 | 899 | |||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | [23],[24] | (162) | (162) | (439) | |||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | [23],[24] | (481) | (481) | (501) | |||||
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | |||||||||
Risk Management Assets | |||||||||
Risk Management Assets | 1,442 | 1,442 | 439 | ||||||
Liabilities, Fair Value Disclosure [Abstract] | |||||||||
Risk Management Liabilities | $ 162 | $ 162 | $ 899 | ||||||
Level 3 Quantitative Information [Abstract] | |||||||||
Forward Price Range Low | $ / MWh | [25] | (5.95) | (5.95) | (14.63) | |||||
Forward Price Range High | $ / MWh | [25] | 11.6 | 11.6 | 20.02 | |||||
Weighted Average Market Price | $ / MWh | [25] | 1.53 | 1.53 | 1.01 | |||||
Cash [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | [1],[26] | $ 201,000 | $ 201,000 | $ 280,000 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [27] | 164,000 | 164,000 | 20,000 | |||||
Cash [Member] | Level 1 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | [1] | 189,000 | 189,000 | 234,000 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [27] | 157,000 | 157,000 | 9,000 | |||||
Cash [Member] | Level 2 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | [1] | 6,000 | 6,000 | 9,000 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [27] | 0 | 0 | 0 | |||||
Cash [Member] | Level 3 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | [1] | 0 | 0 | 0 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [27] | 0 | 0 | 0 | |||||
Cash [Member] | Fair Value Inputs Other [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | [1] | 6,000 | 6,000 | 37,000 | |||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [27] | 7,000 | 7,000 | 11,000 | |||||
Cash [Member] | Indiana Michigan Power Co [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [28] | 164,353 | 164,353 | 19,966 | |||||
Cash [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [28] | 157,409 | 157,409 | 9,418 | |||||
Cash [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [28] | 0 | 0 | 0 | |||||
Cash [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [28] | 0 | 0 | 0 | |||||
Cash [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [28] | 6,944 | 6,944 | 10,548 | |||||
Fixed Income Funds [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 816,000 | 816,000 | 953,000 | ||||||
Fixed Income Funds [Member] | Level 1 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Fixed Income Funds [Member] | Level 2 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 816,000 | 816,000 | 953,000 | ||||||
Fixed Income Funds [Member] | Level 3 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Fixed Income Funds [Member] | Fair Value Inputs Other [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 816,480 | 816,480 | 953,387 | ||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 816,480 | 816,480 | 953,387 | ||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Mutual Funds Fixed Income [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | 90,000 | 90,000 | 81,000 | ||||||
Mutual Funds Fixed Income [Member] | Level 1 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | 90,000 | 90,000 | 81,000 | ||||||
Mutual Funds Fixed Income [Member] | Level 2 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | 0 | 0 | 0 | ||||||
Mutual Funds Fixed Income [Member] | Level 3 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | 0 | 0 | 0 | ||||||
Mutual Funds Fixed Income [Member] | Fair Value Inputs Other [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | 0 | 0 | 0 | ||||||
Domestic [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [29] | 1,067,000 | 1,067,000 | 1,123,000 | |||||
Domestic [Member] | Level 1 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [29] | 1,067,000 | 1,067,000 | 1,123,000 | |||||
Domestic [Member] | Level 2 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [29] | 0 | 0 | 0 | |||||
Domestic [Member] | Level 3 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [29] | 0 | 0 | 0 | |||||
Domestic [Member] | Fair Value Inputs Other [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [29] | 0 | 0 | 0 | |||||
Domestic [Member] | Indiana Michigan Power Co [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [30] | 1,066,427 | 1,066,427 | 1,122,379 | |||||
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [30] | 1,066,427 | 1,066,427 | 1,122,379 | |||||
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [30] | 0 | 0 | 0 | |||||
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [30] | 0 | 0 | 0 | |||||
Domestic [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [30] | 0 | 0 | 0 | |||||
Mutual Funds Equity [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | [29] | 24,000 | 24,000 | 25,000 | |||||
Mutual Funds Equity [Member] | Level 1 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | [29] | 24,000 | 24,000 | 25,000 | |||||
Mutual Funds Equity [Member] | Level 2 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | [29] | 0 | 0 | 0 | |||||
Mutual Funds Equity [Member] | Level 3 [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | [29] | 0 | 0 | 0 | |||||
Mutual Funds Equity [Member] | Fair Value Inputs Other [Member] | |||||||||
Assets, Fair Value Disclosure [Abstract] | |||||||||
Other Temporary Investments | [29] | 0 | 0 | 0 | |||||
Cash and Cash Equivalents [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 164,000 | 164,000 | 20,000 | ||||||
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 164,353 | 164,353 | 19,966 | ||||||
US Government Agencies Debt Securities [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 704,000 | 704,000 | 697,000 | ||||||
US Government Agencies Debt Securities [Member] | Level 1 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
US Government Agencies Debt Securities [Member] | Level 2 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 704,000 | 704,000 | 697,000 | ||||||
US Government Agencies Debt Securities [Member] | Level 3 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
US Government Agencies Debt Securities [Member] | Fair Value Inputs Other [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 704,344 | 704,344 | 697,042 | ||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 704,344 | 704,344 | 697,042 | ||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Corporate Debt [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 62,000 | 62,000 | 48,000 | ||||||
Corporate Debt [Member] | Level 1 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Corporate Debt [Member] | Level 2 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 62,000 | 62,000 | 48,000 | ||||||
Corporate Debt [Member] | Level 3 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Corporate Debt [Member] | Fair Value Inputs Other [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 62,118 | 62,118 | 47,792 | ||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 62,118 | 62,118 | 47,792 | ||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
State and Local Jurisdiction [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 50,000 | 50,000 | 208,000 | ||||||
State and Local Jurisdiction [Member] | Level 1 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
State and Local Jurisdiction [Member] | Level 2 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 50,000 | 50,000 | 208,000 | ||||||
State and Local Jurisdiction [Member] | Level 3 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
State and Local Jurisdiction [Member] | Fair Value Inputs Other [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 50,018 | 50,018 | 208,553 | ||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 50,018 | 50,018 | 208,553 | ||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||
Spent Nuclear Fuel and Decommissioning Trusts | $ 0 | $ 0 | $ 0 | ||||||
[1] | Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | ||||||||
[2] | Included in revenues on the condensed statements of income. | ||||||||
[3] | Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. | ||||||||
[4] | Represents the settlement of risk management commodity contracts for the reporting period. | ||||||||
[5] | Represents existing assets or liabilities that were previously categorized as Level 2. | ||||||||
[6] | Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. | ||||||||
[7] | Represents existing assets or liabilities that were previously categorized as Level 3. | ||||||||
[8] | Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. | ||||||||
[9] | Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. | ||||||||
[10] | Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.'' | ||||||||
[11] | The September 30, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($4) million in 2015 and ($12) million in periods 2016-2018; Level 2 matures $5 million in 2015, $28 million in periods 2016-2018, $3 million in periods 2019-2020 and $2 million in periods 2021-2032; Level 3 matures $2 million in 2015, $63 million in periods 2016-2018, $25 million in periods 2019-2020 and $82 million in periods 2021-2032. Risk management commodity contracts are substantially comprised of power contracts. | ||||||||
[12] | The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. | ||||||||
[13] | Represents market prices in dollars per MWh. | ||||||||
[14] | Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. | ||||||||
[15] | Includes both affiliated and nonaffiliated transactions. | ||||||||
[16] | Included in revenues on the condensed statements of income. | ||||||||
[17] | Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. | ||||||||
[18] | Represents the settlement of risk management commodity contracts for the reporting period. | ||||||||
[19] | Represents existing assets or liabilities that were previously categorized as Level 2. | ||||||||
[20] | Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. | ||||||||
[21] | Represents existing assets or liabilities that were previously categorized as Level 3. | ||||||||
[22] | Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. | ||||||||
[23] | Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” | ||||||||
[24] | Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | ||||||||
[25] | Represents market prices in dollars per MWh. | ||||||||
[26] | Primarily represents amounts held for the repayment of debt. | ||||||||
[27] | Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | ||||||||
[28] | Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | ||||||||
[29] | Amounts represent publicly traded equity securities and equity-based mutual funds. | ||||||||
[30] | Amounts represent publicly traded equity securities and equity-based mutual funds. |
Income Taxes (Details)
Income Taxes (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2015USD ($) | |
Valuation Allowance Excess Tax Basis Of Stock Over Book Value | $ 165 |
Valuation Allowance Deferred Tax Assets Realized | $ 221 |
Income Taxes (Textuals) [Abstract] | |
Pre-2016 TX Income/Franchise Tax Rate | 0.95% |
New TX Income/Franchise Tax Rate | 0.75% |
Anticipated TX Income/Franchise Tax Rate | 1.00% |
Public Service Co Of Oklahoma [Member] | |
Income Taxes (Textuals) [Abstract] | |
Pre-2016 TX Income/Franchise Tax Rate | 0.95% |
New TX Income/Franchise Tax Rate | 0.75% |
Anticipated TX Income/Franchise Tax Rate | 1.00% |
Southwestern Electric Power Co [Member] | |
Income Taxes (Textuals) [Abstract] | |
Pre-2016 TX Income/Franchise Tax Rate | 0.95% |
New TX Income/Franchise Tax Rate | 0.75% |
Anticipated TX Income/Franchise Tax Rate | 1.00% |
Financing Activities (Details)
Financing Activities (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||||
Oct. 22, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | ||
Long-term Debt | |||||||
Senior Unsecured Notes | $ 13,801,000 | $ 13,801,000 | $ 12,647,000 | ||||
Pollution Control Bonds | 1,874,000 | 1,874,000 | 1,963,000 | ||||
Securitization Bonds | 2,072,000 | 2,072,000 | 2,380,000 | ||||
Spent Nuclear Fuel Obligation | [1] | 266,000 | 266,000 | 266,000 | |||
Other Long-term Debt | 1,151,000 | 1,151,000 | 1,101,000 | ||||
Fair Value of Interest Rate Hedges | 0 | 0 | (6,000) | ||||
Unamortized Discount, Net | (31,000) | (31,000) | (24,000) | ||||
Total Long-term Debt Outstanding | 19,426,000 | 19,426,000 | 18,601,000 | ||||
Long-term Debt Due Within One Year | 1,826,000 | 1,826,000 | 2,500,000 | ||||
Long-term Debt | 17,600,000 | 17,600,000 | 16,101,000 | ||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | [2] | 2,956,000 | |||||
Retirements and Principal Payments | 2,131,000 | $ 1,536,000 | |||||
Short-term Debt: | |||||||
Securitized Debt for Receivables | [3] | 750,000 | 750,000 | 744,000 | |||
Commercial Paper | 32,000 | 32,000 | 602,000 | ||||
Total Short-term Debt | $ 782,000 | $ 782,000 | $ 1,346,000 | ||||
Securitized Debt for Receivables | [4] | 0.28% | 0.28% | 0.22% | |||
Comparative Accounts Receivable Information | |||||||
Effective Interest Rates on Securitization of Accounts Receivable | 0.30% | 0.21% | 0.28% | 0.22% | |||
Net Uncollectible Accounts Receivable Written Off | $ 13,000 | $ 16,000 | $ 27,000 | $ 32,000 | |||
Customer Accounts Receivable Managed Portfolio | |||||||
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | 970,000 | 970,000 | $ 975,000 | ||||
Total Principal Outstanding | 750,000 | 750,000 | 744,000 | ||||
Delinquent Securitized Accounts Receivable | 50,000 | 50,000 | 44,000 | ||||
Bad Debt Reserves Related to Securitization, Sale of Accounts Receivable | 16,000 | 16,000 | 13,000 | ||||
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable | 277,000 | 277,000 | 335,000 | ||||
Financing Activities (Textuals) [Abstract] | |||||||
Reacquired Pollution Controls Bonds Held by Trustees | 475,000 | $ 475,000 | |||||
Maximum Percentage Debt to Capitalization | 67.50% | ||||||
Total Commitment from Bank Conduits to Finance Receivables | 750,000 | 700,000 | $ 750,000 | 700,000 | |||
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition | 309,000 | 309,000 | 309,000 | ||||
Includes Debt Included in Liabilities Held for Sale [Member] | |||||||
Long-term Debt | |||||||
Notes Payable | [5] | 374,000 | 374,000 | 357,000 | |||
Total Long-term Debt Outstanding | [5],[6] | 19,507,000 | 19,507,000 | 18,684,000 | |||
Long-term Debt Due Within One Year | [5] | 1,907,000 | 1,907,000 | 2,503,000 | |||
Long-term Debt | [5] | $ 17,600,000 | 17,600,000 | $ 16,181,000 | |||
Includes Principal Payments Included in Discontinued Operations [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | [7] | $ 2,133,000 | |||||
Commercial Paper [Member] | |||||||
Short-term Debt: | |||||||
Commercial Paper | [4] | 0.44% | 0.44% | 0.59% | |||
AEP Subsidiaries [Member] | |||||||
Long-term Debt | |||||||
Long-term Debt Due Within One Year | $ 424,000 | $ 424,000 | $ 431,000 | ||||
Long-term Debt | $ 2,004,000 | 2,004,000 | 2,260,000 | ||||
AEP Subsidiaries [Member] | Notes Payable One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 5,000 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,017 | ||||||
AEP Subsidiaries [Member] | Notes Payable Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | [7] | $ 1,000 | |||||
Interest Rate (Percentage) | 7.59% | 7.59% | |||||
Due Date | 2,026 | ||||||
AEP Subsidiaries [Member] | Notes Payable Three [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | [7] | $ 1,000 | |||||
Interest Rate (Percentage) | 8.03% | 8.03% | |||||
Due Date | 2,026 | ||||||
AEP Generating Co [Member] | Senior Unsecured Notes One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 7,000 | ||||||
Interest Rate (Percentage) | 6.33% | 6.33% | |||||
Due Date | 2,037 | ||||||
AEP Texas Central Co [Member] | Securitization Bonds One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 27,000 | ||||||
Interest Rate (Percentage) | 0.88% | 0.88% | |||||
Due Date | 2,017 | ||||||
AEP Texas Central Co [Member] | Securitization Bonds Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 81,000 | ||||||
Interest Rate (Percentage) | 5.09% | 5.09% | |||||
Due Date | 2,015 | ||||||
AEP Texas Central Co [Member] | Securitization Bonds Three [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 76,000 | ||||||
Interest Rate (Percentage) | 6.25% | 6.25% | |||||
Due Date | 2,016 | ||||||
AEP Texas Central Co [Member] | Securitization Bonds Four [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 57,000 | ||||||
Interest Rate (Percentage) | 5.17% | 5.17% | |||||
Due Date | 2,018 | ||||||
AEP Texas Central Co [Member] | Senior Unsecured Notes One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 250,000 | ||||||
Interest Rate (Percentage) | 3.85% | 3.85% | |||||
Due Date | 2,025 | ||||||
AEP Texas North Co [Member] | Senior Unsecured Notes One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 50,000 | ||||||
Interest Rate (Percentage) | 3.75% | 3.75% | |||||
Due Date | 2,025 | ||||||
AEP Texas North Co [Member] | Senior Unsecured Notes Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 25,000 | ||||||
Interest Rate (Percentage) | 3.27% | 3.27% | |||||
Due Date | 2,022 | ||||||
Appalachian Power Co [Member] | |||||||
Long-term Debt | |||||||
Total Long-term Debt Outstanding | $ 3,955,295 | $ 3,955,295 | 3,980,274 | ||||
Long-term Debt Due Within One Year | 318,020 | 318,020 | 552,212 | ||||
Long-term Debt | 3,637,275 | 3,637,275 | 3,342,062 | ||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | 672,552 | $ 512,702 | |||||
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | |||||||
Maximum Borrowings from Utility Money Pool | 82,417 | ||||||
Maximum Loans to Utility Money Pool | 694,785 | ||||||
Average Borrowings from Utility Money Pool | 46,664 | ||||||
Average Loans to Utility Money Pool | 97,657 | ||||||
Net Loans (Borrowings) to/from Utility Money Pool | (11,689) | (11,689) | |||||
Authorized Short-term Borrowing Limit | $ 600,000 | ||||||
Maximum and Minimum Interest Rates | |||||||
Maximum Interest Rate | 0.59% | 0.33% | |||||
Minimum Interest Rate | 0.39% | 0.24% | |||||
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | |||||||
Average Interest Rate for Funds Borrowed | 0.46% | 0.26% | |||||
Average Interest Rate for Funds Loaned | 0.46% | 0.28% | |||||
Accounts Receivable and Accrued Unbilled Revenues | |||||||
Accounts Receivable and Accrued Unbilled Revenues | 125,153 | $ 125,153 | 159,823 | ||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | |||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | 1,952 | 2,166 | 5,979 | $ 6,626 | |||
Proceeds from Sale of Receivables | |||||||
Proceeds from Sale of Receivables to AEP Credit | $ 355,275 | 354,406 | $ 1,115,492 | 1,137,564 | |||
Financing Activities (Textuals) [Abstract] | |||||||
Maximum Percentage Debt to Capitalization | 67.50% | ||||||
Appalachian Power Co [Member] | Securitization Bonds One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 22,524 | ||||||
Interest Rate (Percentage) | 2.008% | 2.008% | |||||
Due Date | 2,024 | ||||||
Appalachian Power Co [Member] | Notes Payable Affiliated [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 86,000 | ||||||
Interest Rate (Percentage) | 3.125% | 3.125% | |||||
Due Date | 2,015 | ||||||
Appalachian Power Co [Member] | Pollution Control Bonds One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | [8] | $ 86,000 | |||||
Interest Rate (Percentage) | 1.90% | 1.90% | |||||
Due Date | 2,019 | ||||||
Appalachian Power Co [Member] | Senior Unsecured Notes One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | [8] | $ 350,000 | |||||
Interest Rate (Percentage) | 4.45% | 4.45% | |||||
Due Date | 2,045 | ||||||
Appalachian Power Co [Member] | Senior Unsecured Notes Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | [8] | $ 300,000 | |||||
Interest Rate (Percentage) | 3.40% | 3.40% | |||||
Due Date | 2,025 | ||||||
Appalachian Power Co [Member] | Senior Unsecured Notes Three [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 350,000 | ||||||
Interest Rate (Percentage) | 7.95% | 7.95% | |||||
Due Date | 2,020 | ||||||
Appalachian Power Co [Member] | Senior Unsecured Notes Four [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 300,000 | ||||||
Interest Rate (Percentage) | 3.40% | 3.40% | |||||
Due Date | 2,015 | ||||||
Appalachian Power Co [Member] | Land Note [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 28 | ||||||
Interest Rate (Percentage) | 13.718% | 13.718% | |||||
Due Date | 2,026 | ||||||
Indiana Michigan Power Co [Member] | |||||||
Long-term Debt | |||||||
Total Long-term Debt Outstanding | $ 2,060,651 | $ 2,060,651 | 2,027,397 | ||||
Long-term Debt Due Within One Year | 301,148 | 301,148 | 382,187 | ||||
Long-term Debt | 1,759,503 | 1,759,503 | 1,645,210 | ||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | 178,471 | $ 190,550 | |||||
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | |||||||
Maximum Borrowings from Utility Money Pool | 200,032 | ||||||
Maximum Loans to Utility Money Pool | 13,515 | ||||||
Average Borrowings from Utility Money Pool | 136,890 | ||||||
Average Loans to Utility Money Pool | 13,503 | ||||||
Net Loans (Borrowings) to/from Utility Money Pool | (137,496) | (137,496) | |||||
Authorized Short-term Borrowing Limit | $ 500,000 | ||||||
Maximum and Minimum Interest Rates | |||||||
Maximum Interest Rate | 0.59% | 0.33% | |||||
Minimum Interest Rate | 0.39% | 0.24% | |||||
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | |||||||
Average Interest Rate for Funds Borrowed | 0.47% | 0.27% | |||||
Average Interest Rate for Funds Loaned | 0.46% | 0.30% | |||||
Accounts Receivable and Accrued Unbilled Revenues | |||||||
Accounts Receivable and Accrued Unbilled Revenues | 139,481 | $ 139,481 | 137,459 | ||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | |||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | 2,191 | 2,011 | 6,611 | $ 5,836 | |||
Proceeds from Sale of Receivables | |||||||
Proceeds from Sale of Receivables to AEP Credit | 401,518 | 372,422 | 1,192,137 | 1,132,603 | |||
Financing Activities (Textuals) [Abstract] | |||||||
Reacquired Pollution Controls Bonds Held by Trustees | $ 40,000 | $ 40,000 | |||||
Maximum Percentage Debt to Capitalization | 67.50% | ||||||
Indiana Michigan Power Co [Member] | Notes Payable One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | [8] | $ 111,300 | |||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,019 | ||||||
Indiana Michigan Power Co [Member] | Notes Payable Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 18,600 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,016 | ||||||
Indiana Michigan Power Co [Member] | Notes Payable Three [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 20,601 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,017 | ||||||
Indiana Michigan Power Co [Member] | Notes Payable Four [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 26,512 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,019 | ||||||
Indiana Michigan Power Co [Member] | Notes Payable Five [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 16,265 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,019 | ||||||
Indiana Michigan Power Co [Member] | Notes Payable Six [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 1,273 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,016 | ||||||
Indiana Michigan Power Co [Member] | Notes Payable Seven [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 882 | ||||||
Interest Rate (Percentage) | 2.12% | 2.12% | |||||
Due Date | 2,016 | ||||||
Indiana Michigan Power Co [Member] | Other Long Term Debt One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | [8] | $ 100,000 | |||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,018 | ||||||
Indiana Michigan Power Co [Member] | Other Long Term Debt Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 93,500 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,015 | ||||||
Indiana Michigan Power Co [Member] | Other Long Term Debt Three [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 838 | ||||||
Interest Rate (Percentage) | 6.00% | 6.00% | |||||
Due Date | 2,025 | ||||||
Ohio Power Co [Member] | |||||||
Long-term Debt | |||||||
Total Long-term Debt Outstanding | $ 2,166,050 | $ 2,166,050 | 2,297,123 | ||||
Long-term Debt Due Within One Year | 395,938 | 395,938 | 131,497 | ||||
Long-term Debt | 1,770,112 | 1,770,112 | 2,165,626 | ||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | 131,484 | $ 438,583 | |||||
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | |||||||
Maximum Borrowings from Utility Money Pool | 0 | ||||||
Maximum Loans to Utility Money Pool | 367,472 | ||||||
Average Borrowings from Utility Money Pool | 0 | ||||||
Average Loans to Utility Money Pool | 256,020 | ||||||
Net Loans (Borrowings) to/from Utility Money Pool | 279,129 | 279,129 | |||||
Authorized Short-term Borrowing Limit | $ 400,000 | ||||||
Maximum and Minimum Interest Rates | |||||||
Maximum Interest Rate | 0.59% | 0.33% | |||||
Minimum Interest Rate | 0.39% | 0.24% | |||||
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | |||||||
Average Interest Rate for Funds Borrowed | 0.00% | 0.27% | |||||
Average Interest Rate for Funds Loaned | 0.47% | 0.29% | |||||
Accounts Receivable and Accrued Unbilled Revenues | |||||||
Accounts Receivable and Accrued Unbilled Revenues | 354,276 | $ 354,276 | 365,834 | ||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | |||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | 8,545 | 7,213 | 23,228 | $ 21,358 | |||
Proceeds from Sale of Receivables | |||||||
Proceeds from Sale of Receivables to AEP Credit | 670,677 | 668,112 | 1,949,042 | 1,980,764 | |||
Financing Activities (Textuals) [Abstract] | |||||||
Reacquired Pollution Controls Bonds Held by Trustees | $ 345,000 | 345,000 | |||||
Ohio Power Co [Member] | Securitization Bonds One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 45,426 | ||||||
Interest Rate (Percentage) | 0.958% | 0.958% | |||||
Due Date | 2,018 | ||||||
Ohio Power Co [Member] | Pollution Control Bonds One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 86,000 | ||||||
Interest Rate (Percentage) | 3.125% | 3.125% | |||||
Due Date | 2,015 | ||||||
Ohio Power Co [Member] | Other Long Term Debt One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 58 | ||||||
Interest Rate (Percentage) | 1.149% | 1.149% | |||||
Due Date | 2,028 | ||||||
Public Service Co Of Oklahoma [Member] | |||||||
Long-term Debt | |||||||
Total Long-term Debt Outstanding | $ 1,290,973 | $ 1,290,973 | 1,041,036 | ||||
Long-term Debt Due Within One Year | 150,437 | 150,437 | 427 | ||||
Long-term Debt | 1,140,536 | 1,140,536 | 1,040,609 | ||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | 319 | $ 34,010 | |||||
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | |||||||
Maximum Borrowings from Utility Money Pool | 165,947 | ||||||
Maximum Loans to Utility Money Pool | 152,498 | ||||||
Average Borrowings from Utility Money Pool | 113,117 | ||||||
Average Loans to Utility Money Pool | 74,225 | ||||||
Net Loans (Borrowings) to/from Utility Money Pool | 116,345 | 116,345 | |||||
Authorized Short-term Borrowing Limit | $ 300,000 | ||||||
Maximum and Minimum Interest Rates | |||||||
Maximum Interest Rate | 0.59% | 0.33% | |||||
Minimum Interest Rate | 0.39% | 0.24% | |||||
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | |||||||
Average Interest Rate for Funds Borrowed | 0.49% | 0.27% | |||||
Average Interest Rate for Funds Loaned | 0.46% | 0.00% | |||||
Accounts Receivable and Accrued Unbilled Revenues | |||||||
Accounts Receivable and Accrued Unbilled Revenues | 146,039 | $ 146,039 | 112,905 | ||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | |||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | 1,709 | 1,745 | 4,455 | $ 4,417 | |||
Proceeds from Sale of Receivables | |||||||
Proceeds from Sale of Receivables to AEP Credit | $ 411,523 | 398,567 | $ 1,025,909 | $ 1,014,320 | |||
Financing Activities (Textuals) [Abstract] | |||||||
Maximum Percentage Debt to Capitalization | 67.50% | ||||||
Public Service Co Of Oklahoma [Member] | Senior Unsecured Notes One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | [8] | $ 125,000 | |||||
Interest Rate (Percentage) | 3.17% | 3.17% | |||||
Due Date | 2,025 | ||||||
Public Service Co Of Oklahoma [Member] | Senior Unsecured Notes Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | [8] | $ 125,000 | |||||
Interest Rate (Percentage) | 4.09% | 4.09% | |||||
Due Date | 2,045 | ||||||
Public Service Co Of Oklahoma [Member] | Other Long Term Debt One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 319 | ||||||
Interest Rate (Percentage) | 3.00% | 3.00% | |||||
Due Date | 2,027 | ||||||
Southwestern Electric Power Co [Member] | |||||||
Maximum Borrowings from Nonutility Money Pool | $ 0 | ||||||
Maximum Interest Rate for Funds Borrowed from Nonutility Money Pool | 0.00% | 0.00% | |||||
Long-term Debt | |||||||
Total Long-term Debt Outstanding | $ 2,283,966 | $ 2,283,966 | 2,140,437 | ||||
Long-term Debt Due Within One Year | 3,250 | 3,250 | 306,750 | ||||
Long-term Debt | 2,280,716 | 2,280,716 | 1,833,687 | ||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | 306,750 | $ 3,250 | |||||
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | |||||||
Maximum Borrowings from Utility Money Pool | 112,481 | ||||||
Maximum Loans to Utility Money Pool | 299,932 | ||||||
Average Borrowings from Utility Money Pool | 52,596 | ||||||
Average Loans to Utility Money Pool | 121,845 | ||||||
Net Loans (Borrowings) to/from Utility Money Pool | 43,073 | 43,073 | |||||
Authorized Short-term Borrowing Limit | $ 350,000 | ||||||
Maximum and Minimum Interest Rates | |||||||
Maximum Interest Rate | 0.59% | 0.33% | |||||
Minimum Interest Rate | 0.39% | 0.24% | |||||
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | |||||||
Average Interest Rate for Funds Borrowed | 0.46% | 0.28% | |||||
Average Interest Rate for Funds Loaned | 0.48% | 0.27% | |||||
Accounts Receivable and Accrued Unbilled Revenues | |||||||
Accounts Receivable and Accrued Unbilled Revenues | 176,113 | $ 176,113 | $ 148,668 | ||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | |||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | 1,997 | 1,890 | 5,344 | $ 5,035 | |||
Proceeds from Sale of Receivables | |||||||
Proceeds from Sale of Receivables to AEP Credit | 468,027 | $ 466,828 | $ 1,222,294 | $ 1,278,325 | |||
Financing Activities (Textuals) [Abstract] | |||||||
Maximum Percentage Debt to Capitalization | 67.50% | ||||||
Minimum Interest Rate for Funds Borrowed from Nonutility Money Pool | 0.00% | 0.00% | |||||
Maximum Interest Rate for Funds Loaned to Nonutility Money Pool | 0.59% | 0.33% | |||||
Minimum Interest Rate for Funds Loaned to Nonutility Money Pool | 0.39% | 0.00% | |||||
Average Interest Rate for Funds Borrowed from Nonutility Money Pool | 0.00% | 0.00% | |||||
Average Interest Rate for Funds Loaned to Nonutility Money Pool | 0.47% | 0.28% | |||||
Maximum Loans to Nonutility Money Pool | $ 1,948 | ||||||
Average Borrowings from Nonutility Money Pool | 0 | ||||||
Average Loans to Nonutility Money Pool | 1,945 | ||||||
Net Loans To Borrowings From Nonutility Money Pool | $ 1,946 | 1,946 | |||||
Southwestern Electric Power Co [Member] | Notes Payable One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 3,250 | ||||||
Interest Rate (Percentage) | 4.58% | 4.58% | |||||
Due Date | 2,032 | ||||||
Southwestern Electric Power Co [Member] | Pollution Control Bonds One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | [8] | $ 53,500 | |||||
Interest Rate (Percentage) | 1.60% | 1.60% | |||||
Due Date | 2,019 | ||||||
Southwestern Electric Power Co [Member] | Pollution Control Bonds Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 53,500 | ||||||
Interest Rate (Percentage) | 3.25% | 3.25% | |||||
Due Date | 2,015 | ||||||
Southwestern Electric Power Co [Member] | Senior Unsecured Notes One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | [8] | $ 400,000 | |||||
Interest Rate (Percentage) | 3.90% | 3.90% | |||||
Due Date | 2,045 | ||||||
Southwestern Electric Power Co [Member] | Senior Unsecured Notes Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 100,000 | ||||||
Interest Rate (Percentage) | 5.375% | 5.375% | |||||
Due Date | 2,015 | ||||||
Southwestern Electric Power Co [Member] | Senior Unsecured Notes Three [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 150,000 | ||||||
Interest Rate (Percentage) | 4.90% | 4.90% | |||||
Due Date | 2,015 | ||||||
AEP Transmission Company, LLC [Member] | Senior Unsecured Notes One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 60,000 | ||||||
Interest Rate (Percentage) | 4.01% | 4.01% | |||||
Due Date | 2,030 | ||||||
AEP Transmission Company, LLC [Member] | Senior Unsecured Notes Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 50,000 | ||||||
Interest Rate (Percentage) | 3.66% | 3.66% | |||||
Due Date | 2,025 | ||||||
AEP Transmission Company, LLC [Member] | Senior Unsecured Notes Three [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 40,000 | ||||||
Interest Rate (Percentage) | 3.76% | 3.76% | |||||
Due Date | 2,025 | ||||||
Kentucky Power Co [Member] | Other Long Term Debt One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 25,000 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,018 | ||||||
Kentucky Power Co [Member] | Other Long Term Debt Two [Member] | |||||||
Financing Activities (Textuals) [Abstract] | |||||||
Credit Facility | $ 75,000 | $ 75,000 | |||||
Kentucky Power Co [Member] | Other Long Term Debt Two [Member] | Subsequent Event [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 25,000 | ||||||
Due Date | 2,018 | ||||||
Transource Missouri [Member] | Other Long Term Debt One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 20,000 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,018 | ||||||
Transource Missouri [Member] | Other Long Term Debt Two [Member] | |||||||
Financing Activities (Textuals) [Abstract] | |||||||
Credit Facility | $ 300,000 | $ 300,000 | |||||
Transource Missouri [Member] | Other Long Term Debt Two [Member] | Subsequent Event [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 6,000 | ||||||
Due Date | 2,018 | ||||||
AEP Generation Resources [Member] | Pollution Control Bonds One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 50,000 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,015 | ||||||
AEP Generation Resources [Member] | Pollution Control Bonds Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 39,000 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,015 | ||||||
AEP Generation Resources [Member] | Other Long Term Debt One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 500,000 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,017 | ||||||
AEP Generation Resources [Member] | Other Long Term Debt Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Retirements and Principal Payments | $ 500,000 | ||||||
Interest Rate (Variable) | Variable | ||||||
Due Date | 2,015 | ||||||
Wheeling Power Co [Member] | Senior Unsecured Notes One [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 113,000 | ||||||
Interest Rate (Percentage) | 3.36% | 3.36% | |||||
Due Date | 2,022 | ||||||
Wheeling Power Co [Member] | Senior Unsecured Notes Two [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 122,000 | ||||||
Interest Rate (Percentage) | 3.70% | 3.70% | |||||
Due Date | 2,025 | ||||||
Wheeling Power Co [Member] | Senior Unsecured Notes Three [Member] | |||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | |||||||
Issuances | $ 50,000 | ||||||
Interest Rate (Percentage) | 4.20% | 4.20% | |||||
Due Date | 2,035 | ||||||
[1] | Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of September 30, 2015 and December 31, 2014, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the condensed balance sheets. | ||||||
[2] | Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the issuance amount. | ||||||
[3] | Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance | ||||||
[4] | Weighted average rate. | ||||||
[5] | Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. | ||||||
[6] | Amounts include debt related to AEPRO that have been classified as Liabilities Held for Sale on the condensed balance sheets. See "AEPRO (AEP River Operations Segment)" section of Note 6 for additional information. | ||||||
[7] | Amount includes principal payments of debt related to AEPRO that has been classified as Discontinued Operations on the condensed statement of cash flows. | ||||||
[8] | Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. |
Variable Interest Entities (Det
Variable Interest Entities (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Securitization Bonds | $ 2,072,000 | $ 2,072,000 | $ 2,380,000 | ||||||
Securitized Transition Assets | 1,841,000 | $ 1,841,000 | 2,072,000 | ||||||
AEP Credit, Inc. [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Minimum Percentage of Equity AEP Provides | 5.00% | ||||||||
Percentage of Short Term Borrowing Needs in Excess of Third Party Financings | 20.00% | ||||||||
AEP Texas Central Transition Funding Co [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Securitization Bonds | 1,500,000 | $ 1,500,000 | 1,800,000 | ||||||
Securitized Transition Assets | 1,400,000 | 1,400,000 | 1,600,000 | ||||||
Protected Cell Of Energy Insurance Services, Inc. [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Insurance Premium Expense to Protected Cell | 13,000 | $ 16,000 | 27,000 | $ 33,000 | |||||
Transource Energy [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Proceeds from Partnership Contribution | 32,000 | 23,000 | |||||||
PATH West Virginia Transmission Co, LLC [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 21,000 | 21,000 | 21,000 | ||||||
Maximum Exposure | 21,000 | 21,000 | 21,000 | ||||||
Advance Due to Parent [Member] | Dolet Hills Lignite Co, LLC [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 40,000 | 40,000 | 56,000 | ||||||
Maximum Exposure | 40,000 | 40,000 | 56,000 | ||||||
Capital Contribution From Parent [Member] | PATH West Virginia Transmission Co, LLC [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 19,000 | 19,000 | 19,000 | ||||||
Maximum Exposure | 19,000 | 19,000 | 19,000 | ||||||
Retained Earnings [Member] | PATH West Virginia Transmission Co, LLC [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 2,000 | 2,000 | 2,000 | ||||||
Maximum Exposure | 2,000 | 2,000 | 2,000 | ||||||
SWEPCo's Guarantee Of Debt [Member] | Dolet Hills Lignite Co, LLC [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 0 | 0 | 0 | ||||||
Maximum Exposure | 55,000 | 55,000 | 48,000 | ||||||
Current Assets [Member] | AEP Credit, Inc. [Member] | |||||||||
ASSETS | |||||||||
Assets | 977,000 | 977,000 | 980,000 | ||||||
Current Assets [Member] | AEP Texas Central Transition Funding Co [Member] | |||||||||
ASSETS | |||||||||
Assets | 197,000 | 197,000 | 239,000 | ||||||
Current Assets [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | |||||||||
ASSETS | |||||||||
Assets | 163,000 | 163,000 | 149,000 | ||||||
Current Assets [Member] | Transource Energy [Member] | |||||||||
ASSETS | |||||||||
Assets | 12,000 | 12,000 | 2,000 | ||||||
Net Property Plant And Equipment [Member] | AEP Credit, Inc. [Member] | |||||||||
ASSETS | |||||||||
Assets | 0 | 0 | 0 | ||||||
Net Property Plant And Equipment [Member] | AEP Texas Central Transition Funding Co [Member] | |||||||||
ASSETS | |||||||||
Assets | 0 | 0 | 0 | ||||||
Net Property Plant And Equipment [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | |||||||||
ASSETS | |||||||||
Assets | 0 | 0 | 0 | ||||||
Net Property Plant And Equipment [Member] | Transource Energy [Member] | |||||||||
ASSETS | |||||||||
Assets | 184,000 | 184,000 | 98,000 | ||||||
Other Non Current Assets [Member] | AEP Credit, Inc. [Member] | |||||||||
ASSETS | |||||||||
Assets | 1,000 | 1,000 | 0 | ||||||
Other Non Current Assets [Member] | AEP Texas Central Transition Funding Co [Member] | |||||||||
ASSETS | |||||||||
Assets | 1,454,000 | [1] | 1,454,000 | [1] | 1,654,000 | [2] | |||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Intercompany Item Eliminated in Consolidation | 70,000 | 70,000 | 75,000 | ||||||
Other Non Current Assets [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | |||||||||
ASSETS | |||||||||
Assets | 3,000 | 3,000 | 2,000 | ||||||
Other Non Current Assets [Member] | Transource Energy [Member] | |||||||||
ASSETS | |||||||||
Assets | 5,000 | 5,000 | 4,000 | ||||||
Total Assets [Member] | AEP Credit, Inc. [Member] | |||||||||
ASSETS | |||||||||
Assets | 978,000 | 978,000 | 980,000 | ||||||
Total Assets [Member] | AEP Texas Central Transition Funding Co [Member] | |||||||||
ASSETS | |||||||||
Assets | 1,651,000 | 1,651,000 | 1,893,000 | ||||||
Total Assets [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | |||||||||
ASSETS | |||||||||
Assets | 166,000 | 166,000 | 151,000 | ||||||
Total Assets [Member] | Transource Energy [Member] | |||||||||
ASSETS | |||||||||
Assets | 201,000 | 201,000 | 104,000 | ||||||
Current Liabilities [Member] | AEP Credit, Inc. [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 875,000 | 875,000 | 894,000 | ||||||
Current Liabilities [Member] | AEP Texas Central Transition Funding Co [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 283,000 | 283,000 | 322,000 | ||||||
Current Liabilities [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 49,000 | 49,000 | 44,000 | ||||||
Current Liabilities [Member] | Transource Energy [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 47,000 | 47,000 | 21,000 | ||||||
Noncurrent Liabilities [Member] | AEP Credit, Inc. [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 1,000 | 1,000 | 0 | ||||||
Noncurrent Liabilities [Member] | AEP Texas Central Transition Funding Co [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 1,350,000 | 1,350,000 | 1,553,000 | ||||||
Noncurrent Liabilities [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 76,000 | 76,000 | 62,000 | ||||||
Noncurrent Liabilities [Member] | Transource Energy [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 80,000 | 80,000 | 55,000 | ||||||
Equity [Member] | AEP Credit, Inc. [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 102,000 | 102,000 | 86,000 | ||||||
Equity [Member] | AEP Texas Central Transition Funding Co [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 18,000 | 18,000 | 18,000 | ||||||
Equity [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 41,000 | 41,000 | 45,000 | ||||||
Equity [Member] | Transource Energy [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 74,000 | 74,000 | 28,000 | ||||||
Total Liabilities And Equity [Member] | AEP Credit, Inc. [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 978,000 | 978,000 | 980,000 | ||||||
Total Liabilities And Equity [Member] | AEP Texas Central Transition Funding Co [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 1,651,000 | 1,651,000 | 1,893,000 | ||||||
Total Liabilities And Equity [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 166,000 | 166,000 | 151,000 | ||||||
Total Liabilities And Equity [Member] | Transource Energy [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | $ 201,000 | $ 201,000 | 104,000 | ||||||
Great Plains Energy Inc. [Member] | Transource Energy [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Equity and Voting Ownership Percentage | 13.50% | 13.50% | |||||||
Transource Energy [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Equity and Voting Ownership Percentage | 86.50% | 86.50% | |||||||
Appalachian Power Co [Member] | |||||||||
Related Party Transaction, Due from (to) Related Party, Current | $ (11,689) | $ (11,689) | |||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Securitized Transition Assets | 333,491 | 333,491 | 350,170 | ||||||
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Securitization Bonds | 345,000 | 345,000 | 368,000 | ||||||
Securitized Transition Assets | 333,000 | 333,000 | 350,000 | ||||||
Intercompany Item Eliminated in Consolidation | 4,000 | 4,000 | 4,000 | ||||||
Appalachian Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | |||||||||
Billings from Affiliates | |||||||||
Billings from VIE | 63,687 | 50,143 | 164,657 | 154,239 | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Billings from VIE | 63,687 | 50,143 | 164,657 | 154,239 | |||||
Appalachian Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 23,783 | 23,783 | 30,692 | ||||||
Maximum Exposure | 23,783 | 23,783 | 30,692 | ||||||
Appalachian Power Co [Member] | Current Assets [Member] | Appalachian Consumer Rate Relief Funding [Member] | |||||||||
ASSETS | |||||||||
Assets | 10,914 | 10,914 | 18,099 | ||||||
Appalachian Power Co [Member] | Other Non Current Assets [Member] | Appalachian Consumer Rate Relief Funding [Member] | |||||||||
ASSETS | |||||||||
Assets | [3] | 341,127 | 341,127 | 358,264 | |||||
Appalachian Power Co [Member] | Total Assets [Member] | Appalachian Consumer Rate Relief Funding [Member] | |||||||||
ASSETS | |||||||||
Assets | 352,041 | 352,041 | 376,363 | ||||||
Appalachian Power Co [Member] | Current Liabilities [Member] | Appalachian Consumer Rate Relief Funding [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 24,617 | 24,617 | 26,809 | ||||||
Appalachian Power Co [Member] | Noncurrent Liabilities [Member] | Appalachian Consumer Rate Relief Funding [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 325,534 | 325,534 | 347,652 | ||||||
Appalachian Power Co [Member] | Equity [Member] | Appalachian Consumer Rate Relief Funding [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 1,890 | 1,890 | 1,902 | ||||||
Appalachian Power Co [Member] | Total Liabilities And Equity [Member] | Appalachian Consumer Rate Relief Funding [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 352,041 | 352,041 | 376,363 | ||||||
Indiana Michigan Power Co [Member] | |||||||||
Related Party Transaction, Due from (to) Related Party, Current | (137,496) | (137,496) | |||||||
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Payments Made by I&M to DCC Fuel | 29,000 | 28,000 | 86,000 | 84,000 | |||||
Indiana Michigan Power Co [Member] | Billings from AEP Generating Co [Member] | |||||||||
Billings from Affiliates | |||||||||
Billings from VIE | 67,000 | 67,000 | 182,000 | 202,000 | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Billings from VIE | 67,000 | 67,000 | 182,000 | 202,000 | |||||
Indiana Michigan Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | |||||||||
Billings from Affiliates | |||||||||
Billings from VIE | 37,506 | 30,613 | 102,141 | 92,686 | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Billings from VIE | 37,506 | 30,613 | 102,141 | 92,686 | |||||
Indiana Michigan Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 13,676 | 13,676 | 22,480 | ||||||
Maximum Exposure | 13,676 | 13,676 | 22,480 | ||||||
Indiana Michigan Power Co [Member] | Current Assets [Member] | DCC Fuel [Member] | |||||||||
ASSETS | |||||||||
Assets | 104,273 | 104,273 | 97,361 | ||||||
Indiana Michigan Power Co [Member] | Net Property Plant And Equipment [Member] | DCC Fuel [Member] | |||||||||
ASSETS | |||||||||
Assets | 193,447 | 193,447 | 158,121 | ||||||
Indiana Michigan Power Co [Member] | Other Non Current Assets [Member] | DCC Fuel [Member] | |||||||||
ASSETS | |||||||||
Assets | 99,811 | 99,811 | 79,705 | ||||||
Indiana Michigan Power Co [Member] | Total Assets [Member] | DCC Fuel [Member] | |||||||||
ASSETS | |||||||||
Assets | 397,531 | 397,531 | 335,187 | ||||||
Indiana Michigan Power Co [Member] | Current Liabilities [Member] | DCC Fuel [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 98,173 | 98,173 | 86,026 | ||||||
Indiana Michigan Power Co [Member] | Noncurrent Liabilities [Member] | DCC Fuel [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 299,358 | 299,358 | 249,161 | ||||||
Indiana Michigan Power Co [Member] | Total Liabilities And Equity [Member] | DCC Fuel [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 397,531 | 397,531 | 335,187 | ||||||
Public Service Co Of Oklahoma [Member] | |||||||||
Related Party Transaction, Due from (to) Related Party, Current | 116,345 | 116,345 | |||||||
Public Service Co Of Oklahoma [Member] | Billings from American Electric Power Service Corporation [Member] | |||||||||
Billings from Affiliates | |||||||||
Billings from VIE | 29,851 | 24,317 | 77,817 | 71,646 | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Billings from VIE | 29,851 | 24,317 | 77,817 | 71,646 | |||||
Public Service Co Of Oklahoma [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 10,713 | 10,713 | 15,338 | ||||||
Maximum Exposure | 10,713 | 10,713 | 15,338 | ||||||
Southwestern Electric Power Co [Member] | |||||||||
Related Party Transaction, Due from (to) Related Party, Current | 43,073 | 43,073 | |||||||
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | |||||||||
Billings from Affiliates | |||||||||
Billings from VIE | 41,000 | 41,000 | 124,000 | 121,000 | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Billings from VIE | 41,000 | 41,000 | 124,000 | 121,000 | |||||
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | |||||||||
Related Party Transaction, Due from (to) Related Party, Current | 40,000 | 40,000 | 56,000 | ||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 13,593 | 13,593 | 11,462 | ||||||
Maximum Exposure | 108,773 | 108,773 | 115,796 | ||||||
Billings from Affiliates | |||||||||
Billings from VIE | 30,000 | 24,000 | 59,000 | 31,000 | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Billings from VIE | 30,000 | 24,000 | $ 59,000 | 31,000 | |||||
Percentage of VIE Sales of Lignite Produced | 50.00% | ||||||||
Percentage of DHLCs Debt Guaranteed by Each SWEPCo and CLECO | 50.00% | ||||||||
Percentage Of VIE Management Fee Received | 100.00% | ||||||||
Southwestern Electric Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | |||||||||
Billings from Affiliates | |||||||||
Billings from VIE | 39,150 | 32,787 | $ 102,564 | 98,528 | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Billings from VIE | 39,150 | 32,787 | 102,564 | 98,528 | |||||
Southwestern Electric Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 14,295 | 14,295 | 20,772 | ||||||
Maximum Exposure | 14,295 | 14,295 | 20,772 | ||||||
Southwestern Electric Power Co [Member] | Capital Contribution From Parent [Member] | Dolet Hills Lignite Co, LLC [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 7,643 | 7,643 | 7,643 | ||||||
Maximum Exposure | 7,643 | 7,643 | 7,643 | ||||||
Southwestern Electric Power Co [Member] | Retained Earnings [Member] | Dolet Hills Lignite Co, LLC [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 5,950 | 5,950 | 3,819 | ||||||
Maximum Exposure | 5,950 | 5,950 | 3,819 | ||||||
Southwestern Electric Power Co [Member] | SWEPCo's Guarantee Of Debt [Member] | Dolet Hills Lignite Co, LLC [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 0 | 0 | 0 | ||||||
Maximum Exposure | [4] | 95,180 | 95,180 | 104,334 | |||||
Southwestern Electric Power Co [Member] | Current Assets [Member] | Sabine Mining Co [Member] | |||||||||
ASSETS | |||||||||
Assets | 61,025 | 61,025 | 67,981 | ||||||
Southwestern Electric Power Co [Member] | Net Property Plant And Equipment [Member] | Sabine Mining Co [Member] | |||||||||
ASSETS | |||||||||
Assets | 143,815 | 143,815 | 145,491 | ||||||
Southwestern Electric Power Co [Member] | Other Non Current Assets [Member] | Sabine Mining Co [Member] | |||||||||
ASSETS | |||||||||
Assets | 60,160 | 60,160 | 51,578 | ||||||
Southwestern Electric Power Co [Member] | Total Assets [Member] | Sabine Mining Co [Member] | |||||||||
ASSETS | |||||||||
Assets | 265,000 | 265,000 | 265,050 | ||||||
Southwestern Electric Power Co [Member] | Current Liabilities [Member] | Sabine Mining Co [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 40,311 | 40,311 | 36,286 | ||||||
Southwestern Electric Power Co [Member] | Noncurrent Liabilities [Member] | Sabine Mining Co [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 224,371 | 224,371 | 228,349 | ||||||
Southwestern Electric Power Co [Member] | Equity [Member] | Sabine Mining Co [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 318 | 318 | 415 | ||||||
Southwestern Electric Power Co [Member] | Total Liabilities And Equity [Member] | Sabine Mining Co [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | $ 265,000 | $ 265,000 | 265,050 | ||||||
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 1) [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 50.00% | 50.00% | |||||||
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 2) [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Percentage Interest in Rockport Plant Unit 2 Lease | 50.00% | 50.00% | |||||||
AEP Generating Co [Member] | Lawrenceburg Generating Station [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 100.00% | 100.00% | |||||||
Cleco Power, LLC [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Percentage of VIE Sales of Lignite Produced | 50.00% | ||||||||
First Energy Corp [Member] | Allegheny Series [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Percentage Ownership of "Allegheny Series" by a Nonaffiliated Company | 100.00% | ||||||||
Ohio Power Co [Member] | |||||||||
Related Party Transaction, Due from (to) Related Party, Current | $ 279,129 | $ 279,129 | |||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Securitized Transition Assets | 91,899 | 91,899 | 109,999 | ||||||
Ohio Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | |||||||||
Billings from Affiliates | |||||||||
Billings from VIE | 48,471 | 41,212 | 128,608 | 120,696 | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Billings from VIE | 48,471 | $ 41,212 | 128,608 | $ 120,696 | |||||
Ohio Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | 18,770 | 18,770 | 24,695 | ||||||
Maximum Exposure | 18,770 | 18,770 | 24,695 | ||||||
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | |||||||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Securitization Bonds | 187,000 | 187,000 | 232,000 | ||||||
Securitized Transition Assets | 92,000 | 92,000 | 110,000 | ||||||
Ohio Power Co [Member] | Current Assets [Member] | Ohio Phase-In-Recovery Funding [Member] | |||||||||
ASSETS | |||||||||
Assets | 20,236 | 20,236 | 32,676 | ||||||
Ohio Power Co [Member] | Other Non Current Assets [Member] | Ohio Phase-In-Recovery Funding [Member] | |||||||||
ASSETS | |||||||||
Assets | [5] | 175,189 | 175,189 | 209,922 | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||||||
Intercompany Item Eliminated in Consolidation | 81,000 | 81,000 | 97,000 | ||||||
Ohio Power Co [Member] | Total Assets [Member] | Ohio Phase-In-Recovery Funding [Member] | |||||||||
ASSETS | |||||||||
Assets | 195,425 | 195,425 | 242,598 | ||||||
Ohio Power Co [Member] | Current Liabilities [Member] | Ohio Phase-In-Recovery Funding [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 46,592 | 46,592 | 47,099 | ||||||
Ohio Power Co [Member] | Noncurrent Liabilities [Member] | Ohio Phase-In-Recovery Funding [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 147,496 | 147,496 | 194,162 | ||||||
Ohio Power Co [Member] | Equity [Member] | Ohio Phase-In-Recovery Funding [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 1,337 | 1,337 | 1,337 | ||||||
Ohio Power Co [Member] | Total Liabilities And Equity [Member] | Ohio Phase-In-Recovery Funding [Member] | |||||||||
LIABILITIES AND EQUITY | |||||||||
Liabilities and Equity | 195,425 | 195,425 | 242,598 | ||||||
Carrying Amount in AEGCo's Accounts Payable [Member] | Indiana Michigan Power Co [Member] | |||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | |||||||||
As Reported on the Consolidated Balance Sheet | $ 17,000 | $ 17,000 | $ 20,000 | ||||||
[1] | (a)Includes an intercompany item eliminated in consolidation of $70 million | ||||||||
[2] | (a)Includes an intercompany item eliminated in consolidation of $75 million | ||||||||
[3] | (a)Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $4 million and $4 million, respectively. | ||||||||
[4] | (a)Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $40 million and $56 million in 2015 and 2014, respectively. | ||||||||
[5] | (a)Includes an intercompany item eliminated in consolidation as of September 30, 2015 and December 31, 2014 of $81 million and $97 million, respectively. |
Property, Plant and Equipment59
Property, Plant and Equipment Property, Plant and Equipment (Details) - USD ($) $ in Thousands | 9 Months Ended | ||
Sep. 30, 2015 | Dec. 31, 2014 | ||
Asset Retirement Obligations Significant Change | $ 95,000 | ||
Asset Retirement Obligations (ARO) | |||
Beginning Balance | 2,019,000 | ||
Accretion Expense | 76,000 | ||
Liabilities Incurred | 48,000 | ||
Liabilities Settled | [1] | (126,000) | |
Revisions in Cash Flow Estimates | [2] | 30,000 | |
Ending Balance | 2,047,000 | ||
Property, Plant and Equipment (Textuals) [Abstract] | |||
Asset Retirement Obligations (ARO) Liability for Nuclear Decommissioning of the Cook Plant | 1,310,000 | $ 1,270,000 | |
Fair Value of Legally Restricted Assets | 1,740,000 | 1,790,000 | |
Reduction in ARO Liability due to the execution of a joint use agreement with a third party [Member] | |||
Asset Retirement Obligations (ARO) | |||
Revisions in Cash Flow Estimates | 20,000 | ||
Muskingum River Plant [Member] | |||
Asset Retirement Obligations (ARO) | |||
Liabilities Settled | 81,000 | ||
Appalachian Power Co [Member] | |||
Asset Retirement Obligations (ARO) | |||
Beginning Balance | [3],[4] | 148,377 | |
Accretion Expense | 6,239 | ||
Liabilities Incurred | 0 | ||
Liabilities Settled | (23,471) | ||
Revisions in Cash Flow Estimates | 16,977 | ||
Ending Balance | [3],[4] | 148,122 | |
Indiana Michigan Power Co [Member] | |||
Asset Retirement Obligations (ARO) | |||
Beginning Balance | [3],[4],[5] | 1,342,549 | |
Accretion Expense | 47,918 | ||
Liabilities Incurred | 0 | ||
Liabilities Settled | (3,977) | ||
Revisions in Cash Flow Estimates | 5,638 | ||
Ending Balance | [3],[4],[5] | 1,392,128 | |
Property, Plant and Equipment (Textuals) [Abstract] | |||
Asset Retirement Obligations (ARO) Liability for Nuclear Decommissioning of the Cook Plant | 1,310,000 | 1,270,000 | |
Fair Value of Legally Restricted Assets | 1,740,000 | $ 1,790,000 | |
Ohio Power Co [Member] | |||
Asset Retirement Obligations (ARO) | |||
Beginning Balance | [3],[6] | 1,361 | |
Accretion Expense | 62 | ||
Liabilities Incurred | 0 | ||
Liabilities Settled | (8) | ||
Revisions in Cash Flow Estimates | 0 | ||
Ending Balance | [3],[6] | 1,415 | |
Public Service Co Of Oklahoma [Member] | |||
Asset Retirement Obligations (ARO) | |||
Beginning Balance | [3],[4] | 38,020 | |
Accretion Expense | 1,923 | ||
Liabilities Incurred | 5,336 | ||
Liabilities Settled | (125) | ||
Revisions in Cash Flow Estimates | 1,916 | ||
Ending Balance | [3],[4] | 47,070 | |
Southwestern Electric Power Co [Member] | |||
Asset Retirement Obligations (ARO) | |||
Beginning Balance | [3],[4],[7] | 94,394 | |
Accretion Expense | 4,299 | ||
Liabilities Incurred | 12,191 | ||
Liabilities Settled | (3,358) | ||
Revisions in Cash Flow Estimates | 6,349 | ||
Ending Balance | [3],[4],[7] | $ 113,875 | |
[1] | Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the "Muskingum River Plant" section of Note 6. | ||
[2] | Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. | ||
[3] | Includes ARO related to asbestos removal. | ||
[4] | Includes ARO related to ash disposal facilities. | ||
[5] | Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.31 billion and $1.27 billion as of September 30, 2015 and December 31, 2014. | ||
[6] | Not impacted by the CCR rule. | ||
[7] | Includes ARO related to Sabine and DHLC. |
Disposition Plant Severance (De
Disposition Plant Severance (Details) - USD ($) $ in Thousands | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2015 | Dec. 31, 2014 | ||
Severance Costs | $ 29,000 | ||
Vertically Integrated Utilities [Member] | |||
Cost Reduction Initiatives Text [Abstract] | |||
Current Period Severance Costs Percentage | 68.00% | ||
Generation And Marketing [Member] | |||
Cost Reduction Initiatives Text [Abstract] | |||
Current Period Severance Costs Percentage | 32.00% | ||
Disposition Plant Severance [Member] | |||
Cost Reduction Initiatives [Abstract] | |||
Beginning Balance | $ 29,000 | ||
Incurred | 3,000 | ||
Settled | (21,000) | ||
Adjustments | 0 | ||
Remaining Balance | 11,000 | 29,000 | |
Appalachian Power Co [Member] | |||
Severance Costs | 7,112 | ||
Cost Reduction Initiatives [Abstract] | |||
Beginning Balance | 9,304 | ||
Expense Allocation from Aepsc | (6) | ||
Incurred | 849 | ||
Settled | [1] | (6,385) | |
Adjustments | (119) | ||
Remaining Balance | 3,643 | 9,304 | |
Indiana Michigan Power Co [Member] | |||
Severance Costs | 8,185 | ||
Cost Reduction Initiatives [Abstract] | |||
Beginning Balance | 8,023 | ||
Expense Allocation from Aepsc | (2) | ||
Incurred | 351 | ||
Settled | (5,110) | ||
Adjustments | 0 | ||
Remaining Balance | 3,262 | 8,023 | |
Ohio Power Co [Member] | |||
Severance Costs | 80 | ||
Public Service Co Of Oklahoma [Member] | |||
Severance Costs | 288 | ||
Cost Reduction Initiatives [Abstract] | |||
Beginning Balance | 134 | ||
Expense Allocation from Aepsc | (3) | ||
Incurred | 415 | ||
Settled | (121) | ||
Adjustments | 0 | ||
Remaining Balance | 425 | 134 | |
Southwestern Electric Power Co [Member] | |||
Severance Costs | 289 | ||
Cost Reduction Initiatives [Abstract] | |||
Beginning Balance | 84 | ||
Expense Allocation from Aepsc | (4) | ||
Incurred | 0 | ||
Settled | (79) | ||
Adjustments | 0 | ||
Remaining Balance | $ 1 | $ 84 | |
[1] | Settled includes amounts received from affiliates for expenses related to joint plant. |